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PEH:Cold Heavy-Oil Production With Sand

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Vol6EPTCover.png

Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume VI – Emerging and Peripheral Technologies

H.R. Warner Jr., Editor

Chapter 5 – Cold Heavy-Oil Production With Sand

By Maurice B. Dusseault, U. of Waterloo

Pgs. 191-248

ISBN 978-1-55563-122-2
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Introduction

Heavy oil is defined as liquid petroleum of less than 20°API gravity or more than 200 cp viscosity at reservoir conditions. No explicit differentiation is made between heavy oil and oil sands (tar sands), although the criteria of less than 12°API gravity and greater than 10,000 cp are sometimes used to define oil sands.[1][2][3][4] The oil in oil sands is an immobile fluid under existing reservoir conditions, and heavy oils are somewhat mobile fluids under naturally existing pressure gradients. Unconsolidated sandstones (UCSS) are sandstones (or sands) that possess no true tensile strength arising from grain-to-grain mineral cementation.

Before 1985, heavy-oil production was based largely on thermal stimulation, ΔT, to reduce viscosity and large pressure drops, Δp, to induce flow. Projects used cyclic steam stimulation (huff 'n' puff), steam flooding, wet or dry combustion with air or oxygen injection, or combinations of these methods. Until recently, these technologies used arrays of vertical to mildly deviated wells (< 45°). Some methods have never proved viable for heavy oil; these include solvent injection, biological methods, cold gas (i.e., CH4, CO2, etc.) injection, polymer methods, and in-situ emulsification. Also, all high-pressure methods experienced advective instabilities such as viscous fingering, permeability channeling, water or gas coning, and uncontrolled (upward) hydraulic fracture propagation. Marginally economical nonthermal production with vertical wells was used in Canada, but wells typically produced less than 10 m3/d, recovery was less than 5 to 8% original oil in place (OOIP), and small amounts of sand usually entered the wellbore during production.

Several new production technologies have been developed and proved since 1985. Furthermore, several emerging technologies may impact future heavy-oil production substantially. Technologies defined as proved are those for which several commercially successful projects have been implemented in Canada or elsewhere by 2002.

Steam-assisted gravity drainage (SAGD), used in horizontal wells, involves steam injection for viscosity reduction and gravity segregation for flow. [5] Prototype wells were drilled from an underground mine from 1984 to 1986, and the first commercial projects began production in Canada in 2001.

Cold production is nonthermal heavy-oil production without sand. Economical rates are achieved by exploiting the large drainage area of long horizontal wells completed with slotted liners. In Canada, economic success in oils less viscous than approximately 1500 cp is common, even though production rates may drop by 40% per year and the OOIP recovery is less than 10%. This technology has found major application in the Faja del Orinoco in Venezuela, where multilateral branches are added to further increase the well drainage area. [6]

Cold heavy-oil production with sand (CHOPS) exploits the finding that sand ingress can enhance the oil rate by an order of magnitude or more in heavy-oil UCSS. Pressure-pulsing technology (PPT) is a flow rate enhancement method introduced in heavy-oil fields that used CHOPS between 1999 and 2001. [7] The approach, applicable to any liquid-saturated porous medium, involves applying repeated tailored pressure pulses to the liquid phase. This has the effect of suppressing advective instabilities such as viscous fingering or permeability channeling, overcoming capillary barriers, and reducing pore-throat blockage.

Several emerging heavy-oil production technologies are not yet commercially exploited. The two major emerging technologies are vapor-assisted petroleum extraction (VAPEX) and toe-to-heel air injection (THAI). VAPEX is, in terms of physics and flow processes, the same process as SAGD, except that a condensable and noncondensable gas mixture (e.g., CH4 to C4H10) is used to reduce the oil viscosity. [8] VAPEX approaches can be integrated with SAGD approaches, such as by cycling between steam and miscible gases, the use of a mixture, injection of heated gas ("warm" VAPEX), etc. As with SAGD, all VAPEX variations use gravitationally stabilized flow to avoid advective instabilities and achieve higher recovery. THAI, essentially, is in-situ combustion but with horizontal wells so that the combustion products and heated hydrocarbons flow almost immediately downward into the horizontal production well, rather than having to channel through long distances and experience gas override and fingering. [9]

These proven and emerging technologies will be used more and more in hybrid modes to achieve better recovery and investment returns. For example, CHOPS gives high early production rates, but SAGD gives better overall hydrocarbon recovery, suggesting phased or simultaneous use of the methods. Also, different technologies will be found to be suitable for different reservoirs and conditions. SAGD and other thermal methods are very inefficient in reservoirs less than 15 m thick, whereas CHOPS and PPT have been successful economically in such cases. All these technologies will benefit from improvements in thermal efficiency, process control, and cost reductions. [10]

Contents

Overview

What is CHOPS? Where Is It Used?

CHOPS involves the deliberate initiation of sand influx during the completion procedure, maintenance of sand influx during the productive life of the well, and implementation of methods to separate the sand from the oil for disposal. No sand exclusion devices (screens, liners, gravel packs, etc.) are used. The sand is produced along with oil, water, and gas and separated from the oil before upgrading to a synthetic crude.

To date, deliberate massive sand influx has been used only in UCSS (φ ≈ 30%) containing viscous oil (μ > 500 cp). It has been used almost exclusively in the Canadian heavy-oil belt and in shallow (< 800 m), low-production-rate wells (up to 100 to 125 m3/d). Fig. 5.1 shows Canadian heavy oil and extra-heavy oil deposits. Because of the economic success of CHOPS for these conditions, the concepts behind sand influx management are being tried in other oil production processes. The cavity completion approach developed for coalbed methane exploitation is a similar process[11] carried out for similar goals: to increase well productivity by enhancing fluid flow in the near-wellbore region.

Why Heavy Oil?

World conventional oil (light oil greater than 20°API) supply rates will peak eventually and enter into decline because of increasing world demand, inexorable reservoir production rate decline, and the indisputable fact that few new sedimentary basins remain to be exploited. Many believe that this will occur between 2005 and 2010. [12][13] Thereafter, light oil production will decline gradually at a rate that may be slowed but not reversed by the introduction of new technologies such as gravity drainage and pressure pulsing. Fig. 5.2 shows world oil production predictions. Simply put, conventional oil is running out because new basins are running out. Furthermore, exploitation costs are large in deep, remote basins (deep offshore, Antarctic fringe, Arctic basins). Only larger finds will be developed, and recovery will be less than for "easy" basins.

Nevertheless, the world will never run out of oil for several reasons. First, conventional oil comprises a small fraction of hydrocarbons in sedimentary basins. Table 5.1 shows relative hydrocarbon resource size. Second, as technology evolves, other energy sources (ethanol, hydrogen cycle) will displace oil, just as oil displaced coal. Third, even if all the organic carbon (oil, gas, coal, kerogen) in basins is consumed, oil can be manufactured from wood or assembled from its elements, given a sufficiently high commodity price. To put the available heavy-oil resource into context, in Canada alone it is so large (~400 × 109 m3) that, at a U.S. and Canadian consumption rate of 1.2 × 109 m3/yr, there is enough heavy oil to meet 100% of this demand for more than 80 years if the overall extraction efficiency is approximately 30%.

The claim that the world is irresponsible in rapidly consuming irreplaceable resources ignores technical progress, market pressures, and the historical record. [14] Commodities have never been cheaper, efficiency is increasing, and new ideas such as deep biosolids injection may generate new sources of energy or may recycle energy. [15] It is interesting to read the predictions of doomsayers[16] in the context of continued technological advances. For example, the "Club of Rome," with the use of exponential growth assumptions and extrapolations under static technology, predicted serious commodity shortages before 2000, including massive oil shortages and famine. [17]

These predictions relate to heavy oil and CHOPS technology for the following reasons. First, the new production technologies are proof that science and knowledge continue to advance and that further advances are anticipated. Second, oil prices will not skyrocket because technologies such as manufacturing synthetic oil from coal are waiting in the wings. Third, the new technologies have been forced to become efficient and profitable, even with unfavorable refining penalties. Fourth, exploration costs for new conventional oil production capacity will continue to rise in all mature basins, whereas technologies such as CHOPS can lower production costs in such basins. Fifth, technological feedback from heavy-oil production is improving conventional oil recovery. Finally, the heavy-oil resource in UCSS is vast. Although it is obvious that the amount of conventional (light) oil is limited, the impact of this limitation, while relevant in the short term (2000 to 2030), is likely to be inconsequential to the energy industry in the long term (50 to 200 years).

History of CHOPS Development.

History of Sand Production in Canadian Heavy-Oil Reservoirs. The first discoveries in the Canadian heavy-oil belt were made in the Lloydminster area in the late 1920s. [18] High asphaltene-content heavy crude, an ideal feedstock for asphalt products, has been produced since that time. Typically, 10- to 12-mm diameter perforations were used, and pump jacks were limited by slow rod-fall velocity in the viscous oil to a maximum of 8 to 10 m3/d of production, usually less. Operators had to cope with small amounts of sand, approximately 1% in more viscous oils. Small local operators learned empirically that wells that continued to produce sand tended to be better producers, and efforts to exclude sand with screens usually led to total loss of production. Operators spread the waste sand on local gravel roads and, in some areas, the roadbeds are now up to 1.5 m higher because of repeated sand spreading.

The sharp oil price increases in the 1970s and 1980s led to great interest in heavy-oil-belt resources (approximately 10 × 109m3).[19][20] Many international companies arrived and introduced the latest screen and gravel-pack technology but, in all cases, greatly impaired productivity or total failure to bring the well on production was the result. To this day, there are hundreds of inactive wells with expensive screens and gravel packs.

The advent of progressing cavity (PC) pumps in the 1980s changed the nonthermal heavy-oil industry in Canada. The first PC pumps had low lifespans and were not particularly cost-effective, but better quality control and continued advances led to longer life and fewer problems. The rate limits of beam pumps were no longer a barrier and, between 1990 and 1995, operators changed their view of well management. Sand became an asset because more sand clearly meant more oil. Individual well productivity began to rise higher than the 4 to 5 m3/d average. The goal of completion and workover strategies gradually became clear: initiate and maintain sand influx. Old, inactive fields that had produced only 4 to 6% of OOIP could be rehabilitated profitably with large-diameter perforations and PC pumps. More highly integrated sand separation, transportation, and disposal methods were developed.

CHOPS is a new and rapidly developing production technology. Optimal workover strategies, sand-disposal practices, and improved recovery methods (waterflooding, pressure pulsing) are advancing quickly. Given the moderate operating costs and no need for thermal energy, interest in CHOPS as a primary production method is substantial. In 2002, the only serious limitation on the amount of oil in the heavy-oil belt produced by CHOPS is the lack of refinery upgrading capacity. Heavy oil is rich in carbon, heavy metals, and sulfur; therefore, conventional refineries cannot accept it as feedstock. Specialized and costly refineries called upgraders use coking and hydrogenation to produce synthetic crude oil, which then can be refined in a conventional refinery.

CHOPS Status Worldwide. CHOPS has been widely used only in Canada; however, anecdotal evidence suggests that heavy-oil operators in California traditionally took no steps to exclude sand, understanding that screens and sand packs would become blinded and production would cease. In the Duri field in Sumatra, Indonesia, heavy oil is produced by thermal methods, and large amounts of sand accompany the oil. In China, [21] CHOPS was tried with some success in the Nanyang oil field, Hebei, between 1997 and 2000 but was not adopted permanently. In the Liaohe oil field, Liaoning Province, trials were conducted under challenging conditions. Jilin oil field has limited CHOPS production from a 300-m-deep UCSS.

Broad-ranging acceptance of sand influx as a viable production enhancement mechanism has not yet happened despite Canadian production levels of more than 70,000 m3/d in 2000. The reasons for the lack of acceptance include the fear of sand in a producing asset, the nontraditional nature of the production mechanisms, difficulty in production predictions, complexity in properly implementing CHOPS, and the need for sand management and disposal strategies.

Typical CHOPS Well Behavior

CHOPS wells display wide variations in their production histories. CHOPS production depends on the range of factors discussed in Secs. 5.3, 5.4, and 5.7; however, the major aspects of a "typical" CHOPS well include the following factors.

  • When a new well is completed, initial sand influx is large: 10 to 40% of the volume of the (gas-free) produced liquids and solids.
  • Over a period of a few days to several months, the sand rate gradually decays toward a steady-state influx rate (0.5 to 10%), depending on oil viscosity.
  • The oil production rate increases to a maximum several months or more after placing the well on production and then slowly declines as reservoir-depletion effects begin to dominate.
  • All CHOPS production is accompanied by substantial gas production, and GOR values tend to remain relatively consistent over many years.
  • Short-term sand influx rates and oil production rates fluctuate chaotically about the mean value.
  • A successful workover can partly re-establish oil and sand rate but generally not to levels as high as the first cycle.

Fig. 5.3 shows a production profile for a typical CHOPS well, and Fig. 5.4 shows CHOPS well behavior over three production cycles.

The liquid flux pattern is different from that of conventional well behavior. Because there is a peak in the oil-rate curve, there must be at least two counteracting physical mechanisms with different characteristic effects. The well productivity increases because of enhanced fluid conductivity around the wellbore with continued sand production and diminishes as a result of reservoir energy depletion. These two effects combine to give a peak in the production history, followed by a gradual decline as depletion effects begin to dominate. Fig. 5.5 illustrates this behavior. This chapter explores this unusual behavior as well as other CHOPS technical issues.

CHOPS Reservoirs in Canada

Typical Canadian Reservoirs

Heavy-oil development with CHOPS takes place in the Canadian heavy-oil belt (Fig. 5.1) in reservoirs that may range from extensive 3- to 5- m thick blanket sands to 35-m-thick channel sands with sinuous traces no wider than a kilometer. All reservoirs are UCSS with φ ~ 28 to 32% and k ~ 0.5 to 15 darcy, depending on grain size. The highest k values are for occasional gravel seams found in river channel deposits; most reservoirs have average permeabilities of 1 to 4 darcy. It is impossible to obtain undisturbed specimens from these reservoirs because gas exsolution causes irreversible core expansion (the high oil viscosity impedes gas escape). [18] Therefore, porosities are back-calculated from well logs, and permeabilities are back calculated from grain-size correlations and a limited number of well tests.

With the exception of a few geologically older fields, all the heavy-oil UCSS reservoirs in Alberta and Saskatchewan are found in the Lower and Middle Mannville group, an undeformed and flat-lying Middle Cretaceous clastic sequence comprising sands, silts, shales, a few coal seams, and thin (< 0.5 m) concretionary beds. The depositional environment ranged from channel sands laid down in incised valleys carved several tens of meters into underlying sediments, to estuarine accretion plains formed by lateral river-channel migration on a flat plain, to deltaic, shallow marine, and offshore bar sands. The UCSS mineralogy ranges from quartz arenites (> 95% SiO 2 ) to litharenites and arkoses. The more mature sands at the base of the Mannville group tend to be more quartzose.

A typical CHOPS stratum is a 10-m-thick fine- to medium-grained UCSS (D50 of 80 to 150 μm, k = 2 darcy) with So ~ 88%, Sw ~ 12%, and Sg = 0 at a depth, z, of 400 to 800 m. Initial pressure, po , is on the order of 3 to 7 MPa, and reservoirs are most often underpressured. Taking γ¯ as mean overburden unit weight (γ¯=ρ¯z), generally po ~ 0.7 to 0.9 γ¯z.

Fig. 5.6 shows the Faja del Orinoco in Venezuela, which contains one of the richest accumulations of heavy oil in the world, approximately 250 × 109 m3 (similar in scale to the Canadian deposits).

The host Oficina formation is a fluvial and marine-margin deposit. Apparently, there were a number of large estuarine accretion plains and deltaic complexes (at least four) formed by rivers that drained the Guyana shield to the south. The focal area of deposition changed with sea level in response to sedimentation, the formation of the mountains to the north, and the subsidence of the eastern Venezuelan basin. The deposit is a unitary sequence of strata with general east-west continuity. Individual sand bodies range in thickness up to 40 to 45 m, although the majority of "discrete" oil-bearing beds are 8 to 12 m thick, with sharp lower boundaries from lateral erosional migration of channels and more gradational upper boundaries. Good permeability interconnectivity is shown by a high oil-saturation state in the vertical sequence of strata. Some sand bodies are thick channel sands of almost uniform properties over many meters; others contain multiple laminae of silt and have poor vertical flow properties. In general, the upper beds are of lower quality than the lower beds.

The Faja del Orinoco is a remarkably rich deposit, far richer locally than the Canadian deposits, although smaller in total reserves. Many sequences 100 to 150 m thick contain 60% net pay (i.e., 110 to 120 m of total pay), averaging greater than 80% oil saturation. The lower two to three zones have high permeability (3 to 15 darcy), are 20 to 30 m thick, and are laterally extensive. These reservoirs will be developed more extensively with the existing and emerging technologies mentioned previously.

Production Rate Increase Mechanisms


The following four mechanisms are thought to be responsible for the significant oil-rate enhancement in CHOPS wells. [22][23][24][25][26][27][28][29][30][31][32][33][34][35][36][37]

  • Fluid flow rate increases if the sand matrix is allowed to move because the Darcy velocity relative to the solid matrix increases with matrix movement.
  • As sand is produced from the reservoir, a zone of enhanced permeability is generated and grows outward, allowing a greater fluid flux to the wellbore.
  • A sharp pressure drop in highly viscous gassy oil leads to generation of a "foamy oil" zone, which aids continued sand destabilization and helps move solids and fluids toward the wellbore.
  • Solids motion in the near-wellbore environment eliminates fines trapping, asphaltene deposition, and scale development on the formation matrix outside the casing.


Darcy Velocity Increase with Sand Influx

In an immobile porous medium, the Darcy velocity, vf, is taken relative to a fixed reference frame. However, if the matrix is moving, the Darcy velocity is the differential velocity:

RTENOTITLE....................(5.1)

This effect can be substantial in several circumstances.

During early sand influx in viscous reservoirs (μ > 5000 cp), sand content may approach 40 to 45% by volume of the gas-free produced material. The reservoir is mined almost hydraulically, and sand flux is largely responsible for the flow enhancement. However, sand flux diminishes with time, and this effect gradually becomes less important.

If the dominant sanding mechanism is piping channel ("wormhole") growth at the advancing tip, the sand is liquefied at almost the same rate at which the heavy oil is entering the channel tip. Therefore, at the tip, the sand concentration in the fluid is high, and, during flow toward the wellbore, it is diluted progressively by fluid influx from adjacent reservoir zones. The farther the tip is from the wellbore, the more dilution occurs; therefore, the lower the produced sand cut becomes with time.

Sanding implies a continued liquefaction of the sand fabric. Because of the high viscosity, the velocity of the suspended sand grains, v s , is similar to or somewhat less than the fluid velocity, vf. The pressure gradient is

RTENOTITLE....................(5.2)

Here, dp/dl = the 1D pressure drop, μ = viscosity, and kp = a measure of the permeability of the sand-fluid mixture. Thus, little impedance to flow and small pressure drops arise if the solid phase is moving at the same rate as the fluid phase. Theoretical analyses suggest that this process can perhaps double the liquid rate at the well. This effect may remain important locally at the sites in the reservoir where sand is being liquefied.

Permeability Enhanced Zone Development

Solids withdrawal through liquefaction and transport to the well creates "space" within the producing horizon. This space is not a void; it is a "remolded" zone of higher porosity (dilated) sand or it is filled with sand/water/oil/gas slurry. The growth of this remolded zone increases the apparent permeability of the wellbore region. With continued sand production, the well behaves as if it has an increasing radius with time. Assuming that the permeability of the remolded zone is much higher than the virgin formation, the enhancement effect may be expressed as

RTENOTITLE....................(5.3)

The remolded zone is unlikely to be a uniform zone with sharp boundaries. Fig. 5.7 shows the conceptual model considered to be more correct. There is a region near the wellbore in which high-porosity slurry exists, but, for the most part, the zone is viewed as a dilated, partially remolded region with diffuse gradational boundaries. Assuming that the sand in a cylinder dilates from 30 to 35% and that the overburden does not deflect downward, for each cubic meter of sand produced, 20 m3 of reservoir must dilate. If sand is produced mainly from channels rather than a cylindrical zone, the affected region may be much larger. After 100 to 300 m3 of sand has been produced, there is a remolded region of 1000 to 5000 m3, giving an increase of 50-fold to 100-fold in the effective well radius depending on the zone thickness. Production enhancement from this effect alone should approach 4-fold to 5-fold, providing other conditions remain the same.

The remolded zone porosity is indeterminate, but near-wellbore values of 42 to 44% have been calculated with through-the-casing compensated neutron logs. Occasional thin zones beneath shale caprock may register porosities of greater than 70%, indicating that small cavities can be sustained. These values were obtained from a well in which production had been inactive and free gas bubbles had gone back into solution. 44% is close to the maximum porosity for loose sands in grain-to-grain contact under low stress.

3D seismic data taken over a field from which sand was produced show somewhat elongated (elliptical) zones of low seismic velocity and high attenuation.[38] These zones are far larger than expected for an actual cavity, indicating that they are high-porosity zones in which stresses are low but grains are still in contact. Sec. 5.4.5 revisits this issue.

Foamy Behavior in Viscous Oil

The third flow-enhancement mechanism is related to exsolution of dissolved gas. This is a type of solution-gas drive, but there are a number of important differences compared with conventional solution-gas behavior.

The heavy oils exploited by CHOPS have gas (> 90% CH4) in solution; the bubblepoint usually is at or near the pore pressure. Wells are subjected to aggressive drawdown and gas exsolves as bubbles; however, a continuous gas phase is not formed. The gas remains as bubbles that expand in response to pressure decline during flow to the well; hence, the bubbles act as an "internal drive," driving the slurry to the well at a velocity greater than predicted by conventional liquid flow theories (v ∝ 1/r). Because bubbles move with the fluid and discrete gas channels apparently do not develop, there is no direct drainage mechanism to deplete gas pressures far within the reservoir. Thus, gas/oil ratios (GORs) remain constant, and virgin pressures may be encountered in infill drilling only a few hundred meters from existing producing wells.

Foamy oil is developed in an induction zone in which bubbles nucleate in response to –Δp. Assuming that a bubble nucleates in a pore subjected to a pressure gradient, it will displace to block the pore throat, reducing the fluid-flow capacity of the throat and causing the local pressure gradient to rise. Fig. 5.8 illustrates how pore-throat blockage by bubbles leads to higher pressure gradients. This helps destabilize sand because it increases the local drag force on grains. In a porous medium, the hydrodynamic drag force can be expressed as

RTENOTITLE....................(5.4)

Here, the hydrodynamic body force, F, is proportional to the cross-sectional area, A, the grain width, w, and the pressure gradient, ∂p/∂l, corrected by a grain shape factor, S, of less than 1. Fig. 5.9 illustrates the mechanics. During the process, the gradient becomes large enough and the restraining forces small enough to cause the grains to mobilize. This process is known as liquefaction (or piping). A large hydrodynamic force can overcome small amounts of cohesion, although it is more likely that any true cohesion in UCSS is destroyed by the shearing and dilation that precede liquefaction.

Elimination of Skin Effects

Heavy oil contains asphaltenes, which are semisolid materials made of complex organic molecules. These materials precipitate with pressure decline and gas depletion, blocking pores and impairing the production rate of wells. In the interstices of typical heavy-oil reservoirs, there are fine-grained siliceous minerals (silica, clay minerals) that can be mobilized under high-pressure gradients and viscous drag forces. These minerals may accumulate at pore throats and form stable blockages.

If sand is kinematically free to shear, dilate, and undergo liquefaction, pore-throat blockages will continually clean themselves up. This has been confirmed in sand management approaches for high-rate oil wells (see Sec. 5.11.5). Such wells develop more and more "negative skins" as blockages are cleaned up through sand bursts. Although not a physically correct view, a well on CHOPS may be viewed as having a massively "negative" skin.

Change of Mechanisms With Time

During early production, flow distance is short, pressure gradients are large, and sanding rates are high. The effect of sand flow increasing fluid flux dominates enhancement. Foamy-oil processes are developing near the wellbore, aiding destabilization; high initial sand cuts and gas contents in CHOPS wells confirm this.

After approximately 100 to 300 m3 of sand production, the drainage area is large, and larger quantities of oil can slowly ooze across interfaces under the flow gradients. Sand is destabilized locally, but the second process (large drainage area) now dominates fluid flow. Foamy-oil behavior helps drive fluids toward the wellbore and helps destabilize sand, particularly in local zones in which pressure gradients are high. GORs remain constant, which is an important and revealing fact.

In the late life of a CHOPS well, after more than 1000 m3 of sand has been produced, solution-gas-drive depletion begins. GOR values slowly climb, indicating that a connected gas phase or a small gas cap has formed, as indicated by gas slugging in older wells. Water influx is more likely because of coning effects and the large, permeable, near-wellbore region. The CHOPS process can attenuate and decay, and the disturbed, remolded zones can interact between wells.

Apparently, the dominant mechanisms evolve during the CHOPS process. However, if sanding ceases, oil rates always drop precipitously. Sand recompaction and perforation blockage create traps for asphaltenes and clays, almost totally blocking fluid production. In practice, when a well suddenly ceases production without precursor phase changes (e.g., sudden water increase), workover strategies focus on reopening perforations, perturbing the formation, and reducing capillary effects.

Because of their higher density, sand particle flow may be retarded slightly during flow because of inertial effects, and there is a tendency for larger particles to settle more rapidly in the near-wellbore vicinity. Larger particles also arch around perforation openings more effectively. This hydrodynamic sorting may be responsible for the sharp drops in sand and oil production rates often observed in stable producing wells.

Uniform or Channel Growth in the Affected Region?


The two limiting physical mechanisms for sand production are compact growth of the remolded zone as a cylindrical (or spherical or ellipsoidal) body or extension of an anastomosing piping channel system comprising a network of tubes ("wormholes"). These lead to different geometries in situ, although the impact on well productivity may not be quantifiable through measurements.

Uniform Remolded Zone Growth Concepts

Fig. 5.10 shows a compact zone growth hypothesis for CHOPS. In compact growth, the ratio of the area of the fully yielded zone to the volume enclosed approaches a minimum because a cylindrical or elliptical shape is spatially more compact than a channel network. Discrete zonal boundaries do not really exist: a gradual phase-transition zone develops, although it may be treated mathematically as a thin front, just as in a melting alloy. The complex and diffuse boundary shape is approximated by a geometrically regular shape and a distinct liquefaction front. A circular 2D assumption is simplest for analysis because the radius of the zone and, hence, the pressure gradient can be scaled directly to sand-production volume with no additional assumptions. Also, overburden stress, σv, plays a dominant role in the destabilizing and dilation process, and a 2D model cannot capture this process in a rigorous manner.

There are arguments that support a compact growth hypothesis. The yielded zones can support little overburden stress; therefore, σ v must be redistributed outward from the wellbore region (see Sec. 5.4.4). However, the overburden has elasticity and cannot strain into a sharply bent shape or complex curve. It behaves like a thick, stiff beam to smooth and homogenize deformations. Outward extensions of the disturbed zone will shed σv as they yield, whereas stiffer, inward-protruding intact zones will attract σv. Fig. 5.11 illustrates how stress concentrations tend to lead to a compact zone. A high stress concentration cannot be sustained by a UCSS. Shear, dilation, and softening will occur and σv will be cast outward. The overburden stiffness causes σ v to be smoothed by shedding stress to the periphery of the yielded zones (Fig. 5.11 cross sections). Extending this argument to three dimensions, it can be deduced that deformation smoothness is "enforced" by the stiff overburden beam, generating homogenization of yield within a compact growth zone. This keeps the boundary approximately circular to elliptic and suppresses fingering of plastic flow zones.

The surface area in compact growth is minimized because forming compact shapes requires less energy than forming fingered boundaries. For a 10-m-thick reservoir that has produced 500 m3 of sand, the disturbed zone volume may be approximately 5,000 to 10,000 m3 (1:10 ratio) with a mean radius of approximately 13 to 20 m and a minimum surface area of approximately 800 m2. Any frontal perturbations, but particularly channel growth, will increase this area and are, therefore, less probable.

Piping Channel (Wormhole) Growth Concepts

Piping channels are assumed to be stable structures, approximately cylindrical, and of constant cross-sectional area along their length (diameter of approximately 25 to 50 mm). The channel is filled with slowly flowing slurry, and the tips are propagating away from the wellbore. Because the size of the affected zone is influenced more by the impermeable upper and lower reservoir boundaries (cohesive shales), fluid flow will evolve from spherical to cylindrical with radial channel growth. This is analogous to reservoir drainage changes as the radius of influence increases to a value larger than the reservoir thickness.

If the sand-production mechanism is piping-channel growth, there are two reasonable limiting cases for the channel network nature. At one extreme, a number of channels develop outward from the wellbore, and that number is constant with distance. At the other extreme, channels bifurcate and create a 3D anastomosing net in which the volume density of the channels remains constant. These are limiting cases because it is difficult to envision either a decreasing number of channels with distance or an increased channel volumetric density with distance.

For a constant channel-density-per-volume assumption, the channel density is the same within the zone containing channels at all sampling scales larger than the representative elementary volume (REV). Fig. 5.12 illustrates a dendritic piping channel network hypothesis for CHOPS. The mean flow-path length within this zone remains constant with a characteristic value depending on the density of channels. Furthermore, the process zone properties remain the same with growth if the channel density remains constant. In this limiting case, the REV in the channeled zone has an "equivalent permeability," leading to a flow model that has a far-field permeability, ko, a near-field permeability, ki in the remolded zone, and a diffuse-but-narrow transition zone between the two. New channels must be created continuously as the affected zone grows, and the number of channels scales to the area of the boundary.

RTENOTITLE....................(5.5)

The velocity of the affected zone boundary also must be related to the radius.

RTENOTITLE....................(5.6)

The other limiting case for the channel network is where the number of channels remains the same, neither growing nor shrinking with distance from the wellbore. (N is constant with radius, Fig. 5.13). There is no definable REV in this case. The channel density decreases with distance, the mean flow-path length increases, and the equivalent permeability must be defined in a spatially dependent manner, becoming asymptotic to ko at the "boundary" defining the location of the advancing tips. The velocity of the affected zone boundary remains constant, and the flow equations for the constant-N case differ from the flow equations for the dendritic case.

Fig. 5.14 is a schematic plot of the equivalent permeability distribution of the two limiting cases, as well as a reasonable assumption for a compact growth model. One interesting point is that from a flow or well-test perspective, it will be almost impossible to discriminate between these cases as the boundary (or transition zone) moves farther from the wellbore. Strong conclusions as to the physical nature of the processes in the reservoir based solely on tests performed at the wellbore face (Δp or ΔQ well tests) seem problematic.

For piping channels, two possible cases exist with respect to fluid flow and drainage in the reservoir: strong piping case and thin lens case. Fig. 5.15 shows the two limiting flow regimes for piping-channel drainage. In the strong piping case, formation fluid flow is channeled strongly within the "wormhole." Solids and liquid flux are dominated by the tip processes and pressure gradients that drain the reservoir beyond the tip. In the thin lens case, individual channels also serve as drains for surrounding oil. The sanding at the tip is dominated by local gradients, but the permeable channels that serve as drains dominate the overall oil production. In more viscous oils (> 10,000 cp), mobility is low and the sand cut remains elevated for a long time, more closely resembling the strong piping case in which most fluid comes from the tip region. In lower-viscosity oils, the slurry is diluted during transit to the well, which more closely resembles the permeable thin lens model.

The reservoir contact area for channel growth is potentially far larger than for compact growth. With the same example of 500 m3 of sand produced in the compact zone, if channels average 3 cm in diameter, the contact area is approximately 66,000 m2 rather than approximately 800 m2.

Combined Compact and Wormhole Processes

Several arguments suggest that sand production is a result of a combination of mechanisms. Assuming a mean stable-channel diameter of 30 mm, the total channel-network length would exceed 1000 km after 1000 m3 of sand is produced from a well. Stated in another way, in a 10-m-thick reservoir with 10 ha well spacing, each cubic meter of formation will contain approximately 10 m of 30-mm-diameter channels (i.e., only 0.17% of the volume of the reservoir). 1000 km of channels seems improbable, but perhaps the piping channels are substantially larger than 30 mm.

Viscous slurry flowing in small channels with rough walls generates large pressure drops, which limits channel lengths because of the finite Δp available in the reservoir between the liquefaction tip and the wellbore. [39] This is impossible to quantify because no method exists to calculate the number of channels, which is necessary to estimate slurry velocity and pressure drop. Channels of great length seem unlikely, and short channel lengths of approximately 2 to 20 m are assumed.

During early time, when the remolded zone is small and sand production large, it appears that compact growth is dominant. The radius of curvature of the zone is small, and the "intact" wall can sustain higher tangential stresses, σθ, that counteract piping-channel development. The sharper the radius of curvature, the greater the stability of the sand face; thus, any perturbation of the surface will tend to self-heal. Fig. 5.16 shows flowlines focusing and stresses near a perturbation.

When the remolded zone is large, a surface perturbation may lead to stable channel development. Such a perturbation focuses the flowlines, increasing the local gradient at the leading tip of the perturbation. The destabilizing forces (Fig. 5.8) are large because of the spherically convergent flow at the channel tip. However, stabilizing forces linked to friction and arching also increase; a small hole in a granular material is far more stable than a large hole. Finally, the presence of a "free face" will lead to stress concentrations. This favors yield, weakening, and dilation of the sand, which facilitates destabilization and liquefaction.

Whether a perturbation will self-heal or propagate depends on the force balance and whether the energy rate will be positive (self-healing) or negative (propagation). If it is negative, it generates its own high-permeability channel that advances into less depleted zones of the reservoir, accessing (and indeed perhaps seeking) zones in which a higher tip gradient can be maintained. This is the realm of stable channel growth, although components of compact growth nearer the wellbore must still take place because of stress redistribution that helps trigger sand yield. It is unlikely that stable channel growth occurs in intact formations. Even at a porosity of 30%, sands under stress are extremely strong and resistant to piping stresses, so channels likely only propagate in preyielded zones.

This transition between compact and channel growth is not entirely speculative. In the field, communication between wells has been observed repeatedly, mainly for mature wells that have produced appreciable amounts of sand. Furthermore, mathematical perturbation analysis of sand-production models, which couple both flow and stress, confirm that stable channel growth is favored energetically late in the well life. Compact growth is favored in early time.

Stress Changes During CHOPS

Natural and induced stresses drive CHOPS processes. Sand removal leads to high shear stresses that yield and dilate the sand before it is liquefied and flows toward the wellbore as slurry. Fig. 5.17 illustrates the tangential and radial stresses around a slurry-filled cavity. The material adjacent to the void must carry the stresses originally supported by the solid material, leading to concentration of tangential stress, σθ↑, and reduction of radial stress, σr↓, near the boundary. The same effect occurs for vertical and horizontal stresses. In 30% porosity sand, this leads to shear yield, which alters the stress distribution and promotes dilation because σr is low and cannot prevent the sand from dilating.

Implications for reservoir behavior are interesting. A CHOPS reservoir contains regions in which the static sand matrix is stressed greater than originally, regions in which shear has softened and dilated the sand massively, and liquefied regions in which sand grains are not in contact and can transmit no effective stress. The detailed distribution of these zones is unknown, but some inferences can be made from geomechanical analysis.

Yield and dilation of the sand matrix will generate stress distributions around a CHOPS well similar to those around a cavity. Four "zones" with diffuse boundaries may be postulated. Fig. 5.18 shows the distribution of stresses around a compact growth zone.

In the liquefied zone (slurry zone), effective stresses are zero; therefore, the total stress is equal to the fluid pressure and is isotropic. Porosity in this zone must be greater than approximately 50%. Permeability is extremely high, and compressibility is dictated by the slurry composition (oil, sand, water, and gas bubbles).

In the fully remolded plastic flow zone, not yet liquefied, the ratio of effective stresses after shearing and dilation is limited by the residual friction angle for sands (≈ 30° at approximately 40 to 45% porosity); therefore, σ1/σ3 ≈ 3.0. The major principal stress, σ1, is σv because of downward force from the overburden, and σ3 = σr because of the geometry of sand removal. Porosity in this zone changes from approximately 35% at the yielding zone boundary to more than 50% at the liquefaction front. Permeability increases by an order of magnitude across this zone, and rock stiffness gradually disappears as φ → 50%.

Farther from the wellbore where high-shear stresses exist, the formation experiences shear, and strength and cohesion are degraded. This is the yielding zone, and it carries a higher σv, and the σr is low from continuous sand removal. Intact dense UCSS (φ ~ 30%) can withstand a σ1 /σ3 ratio as high as 5 to 6 before yield, but once failure has occurred, the sand continues to yield and weaken. Gradually, σ1/σ3lmax → ~3. Porosity in the yielding zone increases to approximately 35%, and permeability may double across this zone during shear and dilation before the fabric is totally disrupted by plastic flow. There is not much grain crushing if individual grains are strong because the confining stress is decreasing rather than increasing. It is believed that bubble nucleation begins at the 35% porosity region, triggered by the pressure drop enforced at the wellbore and by the fabric dilation, which cannot be accommodated by oil inflow because of the high oil viscosity.

In the intact zone, porosity is still approximately 30%, and the sand has not yet experienced shear distortion, cohesion loss, dilation, or shear yield, although stresses have changed. This zone may be under higher shear stresses than in the virgin state, but it possesses all the properties of intact virgin rock. It is believed that pore pressures remain largely unaffected in the yielding and intact zones because of high oil viscosity (immobility). Infill wells drilled into intact reservoirs often have virgin reservoir pressures even though the fracture gradient (i.e., σh) has diminished.

Stress distributions for such models may be calculated from a combination of nonlinear elastic theory in intact zones and plasticity or damage theory in the weakening and plastic flow zones. Predictions depend strongly on the choice of constitutive law. Because the process is 3D, such a constitutive law must account for the material behavior in a fully 3D stress field, and this is not simple mathematically.

Reservoir-Scale Stress Changes. Both compact and channel growth lead to development of a region of softer material that can carry less of the overburden stress. The total overburden load must still be supported to maintain overall stress equilibrium; therefore, the interwell σv value rises. Fig. 5.19 shows vertical stress trajectories at the interwell scale. At the same time, the lateral stresses, σh, within the reservoir drop because of continuous sand removal. The reservoir is thin (5 to 15 m) compared with its area (hundreds of meters); therefore, σh equilibrium is maintained by redistributing σh stresses into overlying and underlying strata. Fig. 5.20 illustrates horizontal stress trajectories at the reservoir scale.

A major macroscopic effect of sanding is the lowering of σh in the reservoir. Attempts to inject fluids into wells that have produced large amounts of sand show that the fracture gradient has dropped from approximately 17 to 22 kPa/m to as low as 7 to 9 kPa/m, approximately one-third of the vertical stress. In the plastic zone surrounding the well, σv /σh ≈ 3.0. Pore pressures are also low, which suggests that the lower limit of σh is controlled by frictional plastic flow. CHOPS wells cannot be maintained full of liquid. Undiluted fluids break through to nearby producing wells, indicating either open channels or the generation of induced hydraulic fractures. Carefully monitored field tests suggest the flow mechanism is fracturing. The formation acceptance of fluid ceases suddenly, implying fracture closure when pi = (σh) min , whereas in channel flow, a gradual pressure decline is expected (Fig. 5.21).

In a reservoir-scale perturbed stress field with low σh, fractures will propagate toward zones of lowest σh, leading to rapid interwell communication during injection. Communication does not take place with a well that has not produced sand. This behavior is an alternative explanation to the "wormhole" hypothesis, [40][41] which, although widely believed, remains conjectural. All phenomena explained in terms of wormholes can be explained in terms of stress and dilation, but the converse is not true: wormholes do not explain all the phenomena observed. Horizontal stress concentrations above and below the zone (Fig. 5.20) lead to excellent fracture containment if fluids are injected at a later date. However, large-scale injection of hot fluids eventually will result in both repressurization and restressing so that fracture gradients can return and even exceed original values.

Stresses Around a Channel. The stress distributions of channels in UCSS are governed by a combination of frictional yield and nonlinear elastic response. (The modulus of sand is also a function of the effective stress.) Fig. 5.22 shows how the effective stresses around a channel are distributed. At the wall, both the radial and tangential effective stresses must be small if there is no cohesion. (Cohesion likely has been destroyed by yielding and dilation.) A small amount of arching may occur, and capillary effects may exist because of fractional water saturation giving apparent cohesion but of a few kPa at most. [42] The stress reduction is balanced by redistribution farther from the opening, where the confinement effect allows the fabric to withstand larger stresses. This distribution is similar to that around the large zone (Fig. 5.18), except at a smaller scale.

A channel causes a general softening (partial loss of structural rigidity) of a large volume around the channel, which also may be a zone of dilation and enhanced permeability. In a reservoir, many channels lead to an overall softening effect (the "Swiss Cheese" effect), causing large-scale stress redistributions (similar to the compact growth model) between intact reservoir zones and zones containing channels.

Changes in Physical Properties During CHOPS

During CHOPS, all physical properties change at all relevant scales within the affected zone: dilation, stress redistribution, and even gas bubbles affect the macroscopic system response (e.g., with respect to seismics, electromagnetics, gravity, etc.).

In compact growth, permeability and compressibility increase with dilation. Intact 30% porosity UCSS has a solid skeleton compressibility of approximately 10–6 kPa–1, but once yielded and dilated to φ ~ 40% under reduced stress, the compressibility may be approximately 10–4 to 10–3 kPa–1. As final liquefaction takes place, the matrix compressibility becomes indefinable, but the slurry becomes more compressible as gas bubbles grow. Permeability increases dramatically, and hydraulic conductivities may show an even greater increase because of phase saturation changes.

Acoustic velocities drop and the shear wave disappears in the remolded zone as the shear modulus disappears and the bulk modulus is degraded. Acoustic wave attenuation becomes severe in the presence of a large gas-bubble fraction, and the reduction of effective stress also contributes to velocity reduction and attenuation. In Alberta, intact acoustic compressional wave velocities are approximately 3.1 to 3.5 km/s for overburden and 2.5 to 3.0 km/s for oil sands. After sanding, large elliptical zones of low velocity (< 1.5 km/s) and high attenuation develop in the reservoir. Fig. 5.23 illustrates low seismic velocities around CHOP wells. Similar effects would occur for a dendritic channel network. Around each channel, stresses are altered and the presence of a viscous fluid with gas bubbles in discrete channels will degrade seismic velocity and increase attenuation as well.

In disturbed material, all high-frequency waves are filtered rapidly out of wave trains, eliminating seismic monitoring as a means of deciding whether the dominant process is compact growth or channel growth. However, seismic probing can identify the approximate boundaries of the affected zone and help decide if the boundary is relatively sharp. If the boundary is diffuse and the seismic velocity changes slowly with position, either the compact growth zone has a broad diffuse boundary, or the channels are not growing in a dendritic manner with an identifiable front. Conversely, a sharp velocity and attenuation boundary reduces the probability that growth is occurring through propagation of a constant number of channels with distance. More data are needed to address and hopefully resolve these issues.

Reservoir Assessment and Candidate Screening for CHOPS

Canadian Experience Range

The range of reservoir characteristics for CHOPS comes largely from Canadian experience. Table 5.2 contains the range of reservoir characteristics. Because Venezuelan heavy-oil deposits in the Faja del Orinoco represent a huge oil reserve, it is worth repeating that the physical properties and geological histories are similar. [43] The only significant differences are that pressures and gas saturations in the Faja are higher and asphaltenes content lower; therefore, CHOPS should be easier.

Coring and Logging Unconsolidated Heavy-Oil Sands

Obtaining genuinely undisturbed cores of UCSS has proved almost impossible; even pressure coring and rubber-sleeve methods have failed to recover intact core. Thus, explicit values for compressibility, permeability, shear strength, and other mechanical properties are generally unavailable as screening criteria.

When a UCSS core enters the core barrel, it likely is intact, except for the unavoidable damage that arises through loss of effective confining stress. The drilling fluid column exerts a pressure greater than the solution gas initially, providing an effective confining stress. As the core barrel is brought to surface, confinement is lost and gas comes out of solution. To permit gas flow in a 30% porosity sandstone (D50 ~ 100 μm), Sg of 12 to 15% is necessary, but the viscous oil impedes drainage and the water phase is largely immobile. There is no tensile strength in UCSS; therefore, core expansion of at least 5 to 6% occurs rather than oil displacement.

Typically, the best coring practices yield material of 35 to 40% porosity in rich sands, whereas in-situ porosity is 30%. Downhole cooling (to −15°C), [44] pressure core barrels, triple-tube coring with internal liner inside diameter (ID) equal to bit ID, special core catchers, and other methods have been tried with limited success.

Triple-tube core barrels with IDs approximately 5 mm larger than the coring bit ID and modified core catchers that can prevent disaggregated material from extruding are recommended. The core is brought to surface in 6- to 10-m lengths. The liner is removed, divided into 1.5-m lengths, capped with rigid PVC end caps stapled to the liner, and sealed with duct tape. Core segments are placed immediately into insulated boxes, packed with dry ice, transported, and stored in a −15°C refrigerator. Core plugs should be taken in a cold room and allowed to warm only under confining stress.

Logging parameters are not affected by expansion because it does not occur downhole under pressure and because it is straightforward to drill high-quality boreholes in heavy-oil sands. Free gas is seldom found in situ; therefore, porosity estimates from neutron-porosity logging are reliable, providing that corrections have been made for the low hydrogen content of the hydrocarbon.

Determining Material Parameters for Screening and Simulation

Placing expanded cores under in-situ confining stresses does not re-establish original porosities. Cores expanded from 30 to 38% porosities will be returned to porosities of 32 to 34% rather than 30%, leaving permanent disruption. The use of higher stresses will simply lead to grain crushing. Other methods are needed to determine parameters. Fluid parameters are largely unaffected by core disturbance because the heavy oil remains in place at the center of the core, and the pore water has not been affected by filtrate exposure. Of course, basic granulometry and mineralogy also are unaffected.

Phase Saturations and Porosity. Because the in-situ gas content of heavy-oil sands is almost invariably zero, porosity values may be back calculated directly with laboratory data. A preserved core sample is placed in a Dean-Stark extraction device with trichloroethylene, and the masses of water, oil, and dry mineral matter are measured. Porosity is back-calculated from

RTENOTITLE....................(5.7)

for phase volumes and

RTENOTITLE....................(5.8)

for porosity calculation. Vt = Vw + Vo + Vs. The phase specific gravities are known or can be measured in the laboratory. Typical values under in-situ conditions might be Gw = 1.03, Go = 0.97, and Gs = 2.65.

Transport Properties. Permeability values are seriously affected by core expansion; absolute permeability may double if φ → 35 to 36% from 30%. If the expanded volume is filled with water during the resaturation phase of a test, the relative permeability to water, kw, may be increased by an order of magnitude. This occurs because the water sheath surrounding the mineral grains is no longer 5 to 10 μm thick but has increased to 20 to 25 μm, and the flow rate is proportional to the square of the thickness; therefore, an order of magnitude increase in kw is easily obtained.

Determining permeability accurately in the laboratory is difficult for a UCSS containing high-viscosity oil. Well-log permeability estimates may be used, but these may be of dubious value in the more permeable zones. A rigorous comparative study is impossible if all cores are damaged.

Empirical correlations may be used to determine absolute permeability measurements on the best core available. Then an equation such as the Kozeny-Carmen correlation can be used to back-estimate absolute permeability at in-situ porosities. [45] One version, in which permeability is related to porosity, φ , specific surface, Av, tortuosity, τ, and a shape factor, Co, is

RTENOTITLE....................(5.9)

Relative permeabilities to oil and water then can be estimated on the basis of So and Sw values with the use of published correlations and viscosity values.

All diffusivity parameters for Fickian processes, which may be of interest if VAPEX or solvent technologies are used, are sensitive to disturbance as well, and methods of correlation to other materials may be necessary. However, heat transfer coefficients (with no advection) are relatively insensitive to sample disturbance as long as the specimens are under stress and resaturated.

Mechanical Properties. Compressibility factors, shear strength, cohesion, and other mechanical properties are of first-order importance in CHOPS. Core expansion by 5% increases compressibility by one to two orders of magnitude, destroys any slight cohesion, and reduces frictional strength substantially. Tests on specimens obtained by in-situ freezing are far better than tests on disturbed core, [46] yet the values obtained still represent lower limits of true strength values and upper limits of compressibility values. Compressibility values are best determined by applying the in-situ effective stress to samples of highest possible quality and then conducting partial unload/reload cycles and taking the value of compressibility at the unloading part of the cycle once two to three cycles have been applied. Fig. 5.24 illustrates how cyclic testing gives more realistic compressibilities for unconsolidated or poorly consolidated sandstones.

Any intact mechanical cohesion (c′ > 20 kPa) in a weak sandstone will inhibit CHOPS. [30][31][32][33][34][35] To assess empirically whether there is significant cohesion, scan-electron microscopy is useful. Grain contact examination allows identification of grain-to-grain cementation and assessment of the intensity of diagenesis, which leads to granular interlock and high friction angles. If grain-contact mineral cements are absent in a sandstone with porosity greater than 26 to 28%, true tensile strength may be assumed to be zero; however, the cohesion intercept in a Mohr-Coulomb shear-failure criterion plot, nevertheless, may appear to be substantial. This is an artifact of the plotting method because of the highly curved failure criterion, the difficulty of executing reliable triaxial tests at almost zero confining stress, and the practice of performing only three or four tests and fitting a curvilinear envelope to them. Fig. 5.25 illustrates the plotting of strength data on a Mohr-Coulomb diagram.

Sonic log analysis (transit time, dipole sonic, etc.) is not reliable for determining static mechanical strength and compressibility. At best, these methods have correlative and comparative value, but they generally overestimate the stiffness (Young's modulus) of UCSS. If sonic logs have been calibrated carefully to a series of mechanical tests, they have comparative value in that a "prediction" of higher strength can be expected to be correct.

Use of Analogs for Mechanical Properties. The concept of an analog has value: an analog is similar in porosity, mineralogy, and granulometry but may be located in another geological stratum. If the comparison and the geological history indicate a high degree of similarity, the analog material may be used as a substitute for damaged core. For example, the cohesionless 99% SiO2 rounded sandstone of 26 to 28% porosity available from outcrops around Minneapolis, Minnesota, is a valuable analog for quartzose UCSS of similar porosity and fabric.

Outcrop material from the same stratigraphic sequence may be tested rather than expanded core. In the Athabasca oil sands (Fig. 5.1), oil-free outcrops can be sampled and tested to obtain a highly reliable analog to reservoir material. If oil-free zones of the same reservoir exist laterally and will be drilled through, sampling may meet with some success. However, coring a 28 to 32% porosity UCSS at 500 to 1500 m depth is challenging, and the coring procedure and core tools must be designed carefully.

Field Testing for CHOPS Assessment.

Conventional Well Tests for CHOPS. Conventional well-test approaches are irrelevant to CHOPS well assessment for the following reasons:

  • No well-test interpretation equations exist for cases involving simultaneous oil, gas, and sand influx.
  • CHOPS wells develop a high permeability, outwardly propagating zone as sand is produced; thus, the well geometry is not static.
  • Permeability, porosity, and compressibility change and may vary with radius by orders of magnitude.
  • The material at the perforation face is a four-phase slurry, not a fluid.
  • If sand is excluded and a well test is carried out, a typical Canadian CHOPS well will produce from one-third to one-twentieth of the rate when sand is allowed to flow unimpeded.


Pilot Tests. For a suitable candidate, a pilot test is needed to determine if CHOPS is feasible in a new field.

  • A temporary oil-and-sand management system is installed on the lease that is capable of handling up to 100 m3/d of oil and 30 m3/d of sand. Evolving gas must be collected or flared.
  • The well is perforated aggressively in the zone of greatest kh/μ (4 to 6 m of large-hole charges are recommended).
  • The well is cleaned, a properly sized PC pump is landed with a bottomhole pressure gauge, and production is initiated (see Sec. 5.7.1).
  • If sand flow cannot be initiated, progressively aggressive steps are taken to perturb the strata.
  • After sand influx is initiated, the well is produced for as long as possible. (Several months of production are required for evaluation.)
  • Continuous measurements are taken of the volumetric rate of all four phases with time.


Ten to 15 weeks after the start of production, it will be apparent whether sand influx will continue, whether sand rate diminishes with time, whether rapid water-cut increases take place, and so on. Decisions then may be made to drill and produce other wells. If sand influx and production drop rapidly and this behavior is repeated after a workover with even less sand, the formation probably has more cohesion than expected and CHOPS is unsustainable.

Screening Criteria for CHOPS Projects and Wells

At this early stage in CHOPS development, screening criteria are based on limited experience. There will be cases in which these criteria are too restrictive and pilot tests will be necessary.

Geological Factors. The reservoir interval must be a UCSS with relatively low clay content. Finely bedded turbidite sequences are not favorable for CHOPS. The more homogeneous the reservoir, the better the chances of success. Closely interbedded cemented and oil-free zones reduce the probability of success. The reservoir should be relatively flat; high-dip UCSS bodies will lead to casing shear as CHOPS progresses. The absence of faults and significant folding are positive factors, and any UCSS that has been exposed to high compression for geological time is unlikely to be a good candidate. On the basis of Canadian experience, even a 4-m bed can be produced by CHOPS if conditions are suitable.

Mobile water within the zone, or above and separated by thin shale (< 2 m), is highly detrimental to CHOPS. Early water coning and high water cuts occur because CHOPS is a high gradient process. Because lateral coning can occur, placing a CHOPS well within 1000 m of down-dip free water is not recommended. Lateral coning can develop after production initiation if free water is nearby. Also, gas caps are detrimental to successful CHOPS because gas coning will occur, and PC pumps deteriorate rapidly under such conditions.

Extremely coarse-grained sands (D50 > 1000 μm) are not likely to be good candidates, nor are poorly sorted sands with a significant percentage of coarse grains. No explicit criteria can be given for the grain-size distribution, but in candidate rank-ordering processes, an optimum grain-size range is 60 to 250 μm. Extremely angular sands are more likely to form stable zones behind the wellbore, whereas well-sorted, rounded sands zones are more likely to allow CHOPS to be sustained without blockages.

Geomechanic Factors. The major geomechanics criterion is the absence of significant mineral cementation. All reasonable steps, including testing, geophysical data analysis, and microscopic examination, must be taken to assure that cohesive strength is negligible. In-situ stress criteria appear not to be highly relevant to CHOPS success, and mild compressional conditions [(σh)max = σ1] to gravity-dominated strata with low lateral stresses (σv = σ1) are acceptable.

Fluid Parameters. Oil saturation should be high, preferably So > 0.80, although a few exceptions to this are known in Canada (see Sec. 5.9). Extremely high-viscosity oils (> 25,000 cp) can produce through CHOPS. However, instead of growing outward and maintaining sufficient structural stability, the overburden is undermined and collapses prematurely, plugging the well or causing casing buckling. Rather than generating yield, plastic flow, and a small liquefied region around the well, a large liquefied region is generated, and collapse occurs. Also, stable sand cuts rise above 10% for these viscosities, creating massive sand-handling problems that increase operating costs. For these reasons, CHOPS in zones in which the oil viscosity is greater than 15,000 cp is not recommended.

A key factor is sufficient gas in solution to generate foamy oil behavior. Gas bubblepoint should be at least 60 to 70% of po, and the closer po is to hydrostatic (10 kPa/m), the better. Gas-depleted zones are poor candidates, as are massively undersaturated zones.

CHOPS Simulation

Nonconventional Processes in CHOPS

Numerical simulation of CHOPS is particularly challenging because of several unusual factors:

  • There is a solid-to-liquid phase transition (liquefaction) of the matrix.
  • Stresses and stress changes play a major role in sand destabilization and liquefaction.
  • Conventional assumptions of phase equilibrium (i.e., compositional simulation) are not justified.
  • Much of the process is dominated by slurry flow in situ, rather than diffusional flow.
  • Geometrical boundary conditions (altered zone size) change continuously.
  • A significantly greater number of physical parameters must be specified than in conventional simulation.
  • Reservoir parameters change continuously over time and space.
  • There are sampling and testing difficulties for UCSS.
  • The processes involved (phase transition, slurry behavior, etc.) are all strongly nonlinear.

Nevertheless, a decade of efforts has achieved substantial progress toward the correct physical simulation of CHOPS. Adequate simulation models are now available, [47] and progress continues. This section discusses the major physical processes in an attempt to identify first-order controls on CHOPS.

Sand Liquefaction. Sand liquefaction accompanies all CHOPS processes. In this solid-to-fluid phase transition, porosity plays the same role as temperature in the melting of a solid. In fact, porosity should be treated as a thermodynamic state variable in a manner similar to temperature. As in a melting alloy, there is no specific "melting porosity" that defines liquefaction; the process is more complicated.

The reservoir porosity is approximately 30%. The outflow at the wellhead contains approximately 1 to 10% sand and substantial quantities of free gas and, therefore, has a porosity greater than 90%. The system must pass through all intermediate porosities, and the liquefied state is defined as the condition at which grains do not form a continuously linked array (i.e., liquefaction implies that σ′ = 0, σ = p, and no shear stresses can be sustained).

Fig. 5.26 attempts to show how the dominant physical processes change with porosity. To achieve the liquefaction porosity of approximately 50%, the sand fabric must dilate. After liquefaction, dense slurry exists where substantial internal energy dissipates through collisions and sliding between grains. With time, dilute slurry is generated; then, grain collision energy dissipation is negligible compared with the viscous energy dissipation in the fluid phase. Even neglecting the complication of a dispersed bubble phase, one phase transition and three separate regimes exist in the porosity domain encountered in CHOPS.

Dense sands cannot spontaneously liquefy. Under stress, the grains are held in a dense 3D array with high contact forces (normal and shear forces) that cannot be overcome by seepage forces (Fig. 5.9). This fabric must be perturbed and dilated, and stresses must drop to allow liquefaction, reinforcing the first-order importance of geomechanics processes.

Permeability-Enhanced Zone. Permeability cannot be defined near the wellbore in liquefied sand. In the approximately 45% porosity zone, it exceeds 10 to 15 darcy for a 100 to 150 μm sand; in intact sand, a typical permeability is 1 to 3 darcy. Perhaps of equal importance, as sand dilates, pore blockages (clays, asphaltenes, gas bubbles) have much less effect on permeability.

If a compact growth zone exists, an average permeability can be linked to porosity (kφn, where n is an empirically determined exponent). Choosing such a function implies that the mathematical simulation gives a reasonable estimate of porosity and that the porosity is homogeneous (not channeled) at the scale of modeling. These assumptions remain unsubstantiated. Alternatively, some simple function of radius may be used. Fig. 5.27 shows permeability as a function of radius. If the k-enhanced zone is highly irregular, defining a "block-averaged" permeability at an instant is not only difficult; the values also change with time.

Apparently, no easy way of determining the permeability exists because of the nonhomogeneity of the region surrounding the well. Some work[48] shows that a simple model can capture most of the permeability-enhancement effects. Sensitivity analyses clearly show that although a model with a continuous change in permeability [k = f(r)] gives time-derivative plots that are different from a skin model (zero thickness impedance zone), results can be approximated by multizone composite models. However, each additional zone in a composite model has two additional unknowns, making the analysis (or data inversion) more complex. For example, two cylindrical zones around a well give eight total unknowns: three compressibilities, three permeabilities, and two radii. Fig. 5.28 shows composite annular models of permeability distribution.

Foamy-Oil Behavior. The physics of foamy oil have been examined in detail. [49][50][51] Many scientific and technical issues now being studied will gradually affect mathematical simulation of foamy-oil behavior in situ. These issues include the following.

  • Obtaining kinetic exsolution rate data for CH 4 from cold heavy oils (a challenging task). [52][53]
  • Verification or rejection of the hypothesis that a continuous gas phase does not develop in CHOPS or providing another explanation for the constant GOR values.
  • Understanding if the bubble-induction zone is linked physically to the zone of dilation (i.e., bubbles are created only when sufficient new local volume is created by the dilation process).
  • Quantifying the effect of bubbles on relative-permeability values.
  • Confirmation of the nature of the physical processes around CHOPS wells in situ.


Slurry Flow. The flow mechanics of slurries remains a complex, unresolved issue for high-concentration slurries in which internal energy dissipation through collisions can take place. [54]

Conventional Approaches to Simulation

Conventional flow simulation without stress coupling attempts to account for the effects of effective stress change, Δσ′ , through the prediction of volume changes, ΔV, with compressibility, Cm, as ΔV = VCm •Δσ′. To use this equation, a further assumption is made: Δσ′ = −Δp, where the change in pressure is calculated as part of the mathematical simulation. This is a flawed assumption because a change in pressure does not lead to the identical and opposite change in effective stress. The relationship is more complex and must be calculated in a rigorous manner with phase compressibilities. Also, in conventional flow analysis (e.g., the basic equations of Theis, Muskat, and Gringarten), an implicit assumption is that boundary stresses remain constant: Δσ terms do not even arise in the formula. Consider what happens near a vertical well. With production, the pressure near the wellbore drops; therefore, σ′ increases and a small volume change must occur. The rock near the wellbore shrinks slightly, but the overburden rocks have rigidity, so the vertical total stresses are redistributed (Fig. 5.17). The total stresses are not constant; therefore, the Δσ′ = −Δp assumption is invalidated. Analyses of this effect[55] * show that errors in flow rate predictions are as high as 50% during early transient testing.

Other assumptions for conventional simulation also should be revisited. For example, the assumption of local equilibrium (compositional model) is probably insufficient for heavy oils because of the slow diffusion rates; hence, a kinetic model is needed.

History matches of the behavior of laboratory sand packs have been carried out with conventional simulators but with a number of uncontrolled or ill-constrained parameter modifications (solubilities, gas contents, bubblepoints, relative permeabilities, compressibilities, etc.). [56][57][58][59] It is uncertain whether these parameters and laboratory processes have a direct and useful relationship with in-situ mechanisms and the large-scale system alterations that take place. Is it valid to history match CHOPS in specific cases if several first-order physical processes such as stress change, sand dilation and liquefaction, and slurry flow are absent from the model? Furthermore, is it valid to use this "calibrated" model to predict the future behavior of the well or other wells in the field? The answer is not clear, but the direction of simulation is clearly away from calibrated conventional simulation to more rigorous coupled geomechanics simulation.

Stress-Flow Coupling and Physics-Based Modeling

Attempts to develop analytical and semianalytical solutions to CHOPS well production are hampered by the massive nonlinearities and the complexity of the processes. Nevertheless, some progress has been achieved for compact growth and channel models. [30][31][32][33][34][35] These models originated in early attempts to understand stress, dilation, and yield around circular openings. [60][61][62] The sand-flux models are all based on introducing aspects of stress, shear-induced dilation, and concomitant permeability increases with necessary simplifications such as 2D-axisymmetric geometry, ideal elastoplasticity, local homogeneity, limited provision for slurry flow energy dissipation, and so on. In the simplest case, stress changes and flow behavior are expressed in vertically axisymmetric equations so that overburden stress redistribution is not incorporated explicitly. In this case, flux equations reduce to quasi-1D forms.

The Geilikman family of models[30][31][32][33][34][35] links the drawdown rate of wells to the magnitude of sand flux. His model "predictions" of an initially high then declining sand flux, combined with a slowly increasing then slowly declining oil flux, correspond qualitatively with observed field behavior. However, no semianalytical model can simulate the initiation of sand liquefaction and make an a priori prediction of sand flux and oil rate increases based solely on a set of initial conditions, material parameters, and constitutive laws. Currently, all models must be calibrated repeatedly to sand production history to develop realistic predictions.

Simulator development in the 1990s has been based on a coupled stress-flow formula solved with the finite-element method. [63][64][65][66] These methods are far too complex to discuss here, but most aspects of the CHOPS process, with the exception of the slurry-flow component, are being incorporated into modeling on a relatively sound physical basis.

Finally, issues such as arching, fabric evolution, and slurry flow in discrete granular systems can be studied with the discrete-element method in which individual particles are allowed to interact and fluid-flow forces can be included. [67] These methods promise to generate insight into effects such as capillarity changes[42] and the destabilizing of sand arches, an extremely difficult problem that is not amenable to continuum mechanics approaches. However, these are physics-based models. They are not design models that use volume-averaged properties, and they are not likely to be used in reservoir simulation.

Operational Issues in CHOPS

Well Completion Practices

Perforating a CHOPS Well. To initiate sand influx, a cased well is perforated with large-diameter ports, usually of 23 to 28 mm diameter, fully phased, and spaced at 26 or 39 charges per meter. More densely spaced charges have not proved to give better results or service, but less densely spaced charges (13 per meter) give poorer results. More densely spaced charges may eliminate reperforating as a future stimulation choice because full casing rupture is likely to take place. In thin intervals (<6 m), the entire interval is perforated. In thicker intervals (> 10 m), a 6- to 8-m zone is perforated. Shallow-penetrating perforations with large explosive charges shock and disrupt an annulus of sand around each perforation channel and, therefore, around the entire casing because these damaged zones likely overlap. Fig. 5.29 illustrates how aggressive perforation damages formation but helps initiate CHOPS. Shaped charges that leave a negligible amount of metallic debris in the formation are used to avoid impairing the elastomer in the PC pump when debris re-enters the well.

The optimum perforation-placement strategy is debatable. The perforated zone is either the bottom of the producing interval or the subzone with the best kh/μ value. Insufficient data exist to claim one approach is superior to the other. The author favors perforating in the lower part of the reservoir, retaining the flexibility to add perforations later higher in the interval. However, it is probably worthwhile to avoid perforating gravel zones with D50 > 2 to 3 mm because gravel is more likely to block perforation ports and damage the pump. In many cases, particularly in channels, gravel zones are at the base of the interval. The lowermost perforations should be placed above these zones.

Initiating Production and Pumping in CHOPS Wells. The large sand influx in CHOPS wells increases well rates, but it carries the risk that the pump may plug and a workover may be required. Therefore, bringing a well onto production is a gradual process.

The pump is started while liquid, called load fluid, and usually lighter oil is introduced in the annulus. When the system is flowing freely, the load fluid rate is diminished to increase drawdown, and sand should begin to enter the wellbore. Drawdown and load fluid rate can be balanced to keep the pump operating effectively, but eventually load fluid input is stopped (within a day or two). If well capacity is sufficient, the pump is operated at maximum speed for the torque output, which is controlled at the drive head. If pump capacity exceeds the well capacity to deliver slurry, a lower speed is used.

CHOPS wells are maintained in an aggressively drawn-down condition, which increases the effectiveness of the foamy-oil mechanism in destabilizing sand and maintaining free flow into the perforations (low backpressure encourages gas and formation expansion). If BHP data are continuously available, they can be used to control the pump speed to maintain a 15- to 20-m annulus fluid level. Otherwise, regular fluid-level measurements are taken acoustically to optimize well performance.

Gas will evolve from the annulus because of gas breaking out of the slurry as it enters the wellbore and flows down past the stator housing. In Canada, this gas is collected and used to run pump motors and to heat the oil storage tanks on the production site.

Progressing Cavity Pumps. PC pumps currently are widely preferred over other pumps. Starting from poor life spans in the early 1980s, they have evolved into highly reliable, versatile devices capable of pumping slurries with high sand content for 15 to 20 months. Rapid technology advances are occurring, including the use of "sloppy-fit" pumps in heavy oil, two-stage pumps, [68] helicoidal stator housings, [69] compact surface hydraulic drives, [70] and so on.

A few guidelines for PC pump use that have evolved from practice are included here.

  • Wells should be drilled with a 20- to 30-m-deep rathole below the production zone to hold any large slugs of sand that enter during the production initiation phase.
  • Pumps (7 to 70 m3/d/100 rev/min) should be sized appropriately for the expected volumes and depth.
  • A 60- to 100-cm-long tailpipe with large vertical slots (10 mm wide, 100 mm long), open bottom, and welded horizontal tag bar (to prevent rotor drop in case of a failure) is attached to the end of the stator.
  • The stator is installed in the wellbore with 3½-in. tubing with its base landed 1 m below the lowermost perforation.
  • The antitorque anchor tool may be installed above or below the stator, depending on factors such as desire to maximize annulus gas recovery (tool below) or fear of plugging (tool above).
  • Rotors are chromium plated or treated with boron to resist sand erosion and prolong life.
  • During production, the end of the rotor should extend below the bottom of the stator by 10 to 50 cm so that it rotates in the upper part of the tailpipe.
  • 25-mm ordinary continuous-drive rods or conventional sucker rods are used to drive the rotor. Various hard facings and antiwear devices are installed on the rods or the tubing to reduce tubing wear. (The relative value of different approaches remains to be assessed.)
  • The pump must never be allowed to run dry through excessive formation gas throughput or because of excessive drawdown. The annulus must not be shut in so that gas buildup occurs.
  • The rotor-seating level and the tubing and stator orientation must be changed at regular intervals to avoid wearing through the tubing.


Other Lifting Approaches. Reciprocating pumps are limited by slow rod-fall velocities. Gas lift is impractical, downhole jet pumps have been researched but never installed, and conventional electrosubmersible pumps still cannot handle sand.

If it is necessary to clean a well of a great deal of sand or if the sand cut is extremely high, a continuous sand-extraction pump based on stroking the tubing has been developed that can move sand at 60% porosity. [71] PC pumps with rotating tubing that eliminate the rod string are under development, although casing wear will still be an issue. Downhole hydraulic drive for the rotor of the pump is available, and downhole electrical drives for PC pumps are being developed. For general use, the PC pump will likely remain the dominant device in CHOPS, but the advent of different drive systems will help improve lifting operations.

Mechanical Problems. Pump manufacturing companies keep detailed records of reasons for pump failures. Reasons for pump failure include elastomer failure through ripping because of the intake of a piece of metal or a large pebble, elastomer embrittlement and failure if run dry, excessive rotor or stator wear, and torque off of the drive rods because of a sudden slug of sand. Additional reasons for pump failure are wear-through of the tubing, release of the no-turn anchor, and a failure of the surface drive system that allows sand to settle on the pump, which prevents startup.

Production-Decline Mechanisms

In addition to mechanical problems, CHOPS wells may suffer production declines that are sudden or gradual. Careful data gathering for each well over time is needed for correct diagnosis. [72]

Within-Wellbore Processes. For reasons that are poorly understood but probably related to stress-induced collapse and liquefaction of a region, a well that has been producing at a low sand cut may suddenly experience a massive, temporary influx of sand. Annulus blockage (between the stator and the casing) or pump blockage can occur. If the well begins to evidence a high water cut with a high sand rate, the lifting capacity may be seriously impaired. This allows sand to pile up in the tubing, causing rods to stop rotating or simply to plug upward flow. If power is removed suddenly from the surface equipment, sand settles onto the pump or slow sand influx into perforations blocks the flow path.

Near-Wellbore Processes. A frequent production-decline mechanism is the gradual plugging of perforations by sand, which is most common with small perforation ports and large sand grains. The drop in production occurs gradually until just a few perforations are producing. Production can cease suddenly if a sand slug is generated.

Some wells cease production not by perforation plugging but by near-wellbore sand recompaction. Perhaps the decline of solution-gas bubble drive allows the sand to stop moving and recompact. Compaction also may involve a segregation process: larger grains settle to the bottom of the liquefied zone, gradually blocking more perforations.

Gas tends to break out near the wellbore, filling the top of the liquefied zone and building a local gas cap that grows until it intersects the uppermost perforations (perhaps aided through coning) and eliminates oil production. Gas also can ruin the pump through overheating.

Remote Reservoir Processes. Lateral water coning has destroyed productivity prematurely in some CHOPS reservoirs. On the other hand, some fields have produced for more than 12 years with less than 20% water cut. In a part of Alberta's Lindbergh field located up a shallow dip from an active water zone, wells progressively watered out updip, indicating that the water source was a remote (800 to 2000 m distant) water zone. High drawdowns in 10,000 cp oil promote coning and, because conventional water shut-off technologies appear useless in CHOPS wells, solutions to coning are difficult.

Highly viscous oils that have resided in place for millions of years may be truly immobile under low gradients. In other words, the highly polar molecules (asphaltenes and resins) have become structured so that the substance has a small yield point that must be overcome. Encountering interwell virgin pressures in zones surrounded by long-term producing wells confirms the existence of a yield point, although the specific mechanics remain conjectural. As the disturbed zone around a CHOPS well grows and sand rates diminish, it is possible to "disconnect" the virgin far-field pressure regime from the sand-producing zone. Then, well productivity drops as the interior zone is depleted. Once this disconnect happens, the only solution is to break through the barrier.

Part of the reason for disconnection is that stable sand zones can develop in the interwell regions, similar to pillars in mines (Figs. 5.19 and 5.23). Because of low gradients and a fluid yield point, the sand can no longer be destabilized by gas exsolution and overburden stresses, leading to slow cessation of sand and fluid influx. In some fields (e.g., Lone Rock, Saskatchewan), wellbore pressures less than 1.0 MPa after 30 years shut-in indicate a lack of flow communication with the far field. However, many wells in that field have been rehabilitated successfully through aggressive workovers that "reconnected" with extant far-field pressures and likely destabilized the interwell stable regions so that gravity-induced sand drive could once again be generated.

Finally, general pressure depletion through depletion of the solution-gas drive causes irreversible production declines; however, whether gas can actually flow from a distance in an intact heavy-oil sandstone is open to question. Some fields have produced for more than a decade with constant GOR, indicating a lack of drainage beyond the gas induction and damaged zone.

Workover Strategies

Given the reasons for production cessation, reinitiation or maintenance of sand influx is fundamental to all workover approaches. Without sand influx, oil rates will be uneconomical. Also, because of low fracture gradients in the well, no fluids will return to surface without artificial lift.

Fluid-Loading Properties. While the pump is running, fluids are introduced down the annulus, perhaps quite aggressively, to perturb the near-wellbore region, to help the pump move fluids, and to introduce chemicals into the wellbore region. Lighter oils (cleaned dead oil), perhaps of 17 to 20°API, can be heated to 70 to 90°C and pumped rapidly into the annulus. Alternatively, clean oil from the site stock tank (usually at 60 to 80°C because of tank heating and, therefore, lower viscosity) can be cycled back to the annulus. Even large slugs of water (approximately 5 to 10 m3), perhaps with chemicals to reduce capillary effects, can be flushed down the annulus while the pump is moving. These methods do not require a shutdown and are effective for near-wellbore problems only.

To avoid a complete workover, a winch truck can withdraw the rotor, and similar tactics can be used through the stator. In this case, as long as the tubing is flushed of sand, the treatment can be allowed to soak in the reservoir before the rotor is replaced and production reinitiated.

Well Cleanout and Perforation Flushing. During a pump change out or tubing withdrawal, sand is cleaned from the well, and chemical soaks or other treatments may be used. Sand is removed with mechanical bailers, with pump-to-surface units (the well cannot give returns to surface), or with light foam-based workover fluids. In all cases, sand is removed to a depth of several meters below the perforations. This may require removing a great deal of sand because perforations will continue to produce sand, particularly when a mechanical wireline bailer is rapidly returned to surface, swabbing the wellbore. Perforations are flushed as thoroughly as possible, and chemical soaks are common at this juncture.

Reperforation and Rocket Propellant Stimulation. Reperforation is used commonly to provide larger ports in old wells, to reduce sand inflow restrictions around the wellbore, and to perturb the wellbore environment and break down stable-sand zones. It is quite effective but, at most, two reperforations are feasible before the casing is ruptured. The beneficial effect likely extends no more than 1 to 2 m from the wellbore.

Ignition of small rocket propellant charges downhole has the benefit of blowing open all the perforations and shocking the zone around the wellbore with a large sudden outward surge. The shock probably perturbs a zone of approximately 4 to 6 m radius around the wellbore.

Pressure-Pulse Workovers, Pulsed Chemical Placements. Aggressive pulsing to perturb the wellbore region was introduced in 1998. [73] The liquid in a closed chamber (V ~ 200 L) at hole bottom, sealed from the annulus, is expelled suddenly through the perforations into the formation. The pressure pulse generated has a lower rise time and amplitude than with rocket propellant, but the impulse is repeated, perhaps 500 to 1,000 times in a 5-to 24-hour period, so that as much as 50 to 100 MJ of energy can be introduced. (Reperforation may involve 3 to 4 MJ, but at a high rate.) Beneficial effects appear to accumulate as more perforations are opened and the region near the wellbore is resaturated. The large energy input in each stroke has a cumulative effect, and an increase in pressure in the near-wellbore region typically reduces the gas saturation and allows the far-field effect to become more substantial. Measurements in offset wells (300 m) show that distant increases in flow rate may be triggered, showing that the effect propagates far beyond the wellbore. Pressure pulsing is the only method that can affect the interwell region by destabilizing distant zones and reconnecting the well with extant far-field pressures. It has been highly successful in initiating sanding in new wells that did not respond to standard sand-flow initiation procedures.

Aggressive pulsing, combined with the outward propagating wave of porosity dilation generated in each stroke, helps overcome problems of viscous fingering and preferential flow through high permeability streaks. This characteristic has resulted in new chemical-placement methods. [74] Pulsing tool recharge from uphole (chemical) or from the formation can be varied to control concentrations of treatment fluids. The rapid downstroke forces fluids aggressively through the perforations, promoting full mixing with reservoir fluids. Fingering is suppressed by pulse placement; therefore, conformance is improved. Achieving good conformance during placement is particularly important in heavy oils because of slow diffusion rates.

Surface Facilities and Transportation. Because of the cold Canadian climate, the high oil viscosity and slow production rates, and the water cut in produced fluids, underground flowlines are used only on multiple well pads or if a well is adjacent to a battery or central facility. Tanker truck or load-haul-dump units transport produced streams (sand, oil, and water). Regional batteries collect and clean the oil and, except for one heated pipeline in Alberta, diluent (up to 15% naptha) is used for pipelining. Smaller-diameter diluent-return pipelines may be installed from upgraders to regional batteries.

Sand Management in CHOPS

Environmental Issues and Waste Definitions

In Canada in 1997, approximately 330,000 m3 of sand (approximately 45% porosity sand at surface) were produced from CHOPS wells. Individual wells may produce as much as 10 to 20 m3/d of sand in the first days of production and may diminish to values of 0.25 to 5 m3/d when steady state is achieved. Sand grain size reflects most of the reservoir. There is little sorting or segregation in the slurry transport to the well; however, not all zones in the reservoir may be contributing equally at all times.

Sand separated from the production stream contains 1 to 6% oil by weight: the more fine-grained the sand, the higher the residual oil content. Separated sand also contains large amounts of chlorides-rich formation water, generally approximately 30,000 to 50,000 ppm NaCl. This means that water-saturated waste sand of 40% porosity contains more than 3,000 ppm chlorides. In Canada, this changes the environmental classification and disposal methods.

Produced sand is classified as nonhazardous oilfield waste. Other wastes that must be disposed of include produced water (usually cleaned and reinjected), as well as liquid wastes that contain various amounts of oil and suspended fine-grained mineral matter, generically called "slops." A particularly difficult material to dispose of is stable emulsion, which is a mixture of water, 20 to 50% oil (enriched in polar asphaltenes), and fine-grained mineral matter. Emulsions are generated during production and tank cleaning when high shear occurs. Attempts to break the emulsion are costly because the oil recovered does not pay for the treatment. This troublesome material represents a difficult challenge for the CHOPS industry.

Separation and Stockpiling Produced Sand

Insulated vertical separators (stock tanks) of 100 to 200 m3 capacity, 6 to 8 m high, and heated to 60 to 80°C receive oil directly (usually one tank per well). Well rates are generally less than 30 m3/d; therefore, residence time is sufficient for heating and effective gravitational segregation. Without interrupting production, oil, water and sand are withdrawn from stock tanks periodically to keep levels within certain ranges.

Tank are cleaned in several ways. Fig. 5.30 illustrates tank designs and cleaning methods. The most common method is to introduce "stingers" (high-pressure hoses) from pressure-treatment trucks to slurry the sand, which is then aspirated into vacuum trucks attached to other ports. This process generates additional emulsion because of intense shear, which creates another treatment and disposal problem, but this tank-cleaning process is the most widely used.

Auger systems have been developed to remove sand without introducing additional water. Through a specially designed port, a robust auger is screwed into the bottom of the tank, and the almost-solid sand slurry is withdrawn to a sealed tub truck. This method reduces the amount of waste generated.

Vacuum trucks and load-haul-dump units (tub trucks) transport the sand either directly to a disposal site or to a site where excess liquid is withdrawn. Sand is dumped into managed stockpiles separated by membranes from underlying surficial strata with run-off capture trenches and with groundwater quality monitoring for environmental control.2,3 If produced sand is left in a stockpile to drain before disposal, Cl content usually decreases to less than 3,000 ppm, which is the limit for landfill placement.

Sand and Fluids Disposal

Land Spreading, Road Spreading, Road Encapsulation, and Reuse. Land spreading (land farming) and road spreading are becoming less acceptable. No new sites for land spreading have been permitted in Canada since 1990, and Canadian regulatory agencies have indicated that road spreading will be phased out. Direct road spreading is acceptable on local nonpaved roads, but the uniform and fine-grained sand is quite unstable, leading to greater road maintenance needs.

Manufacturing high-quality asphalt concrete with produced sand is difficult because of the uniform grain size and the strong dilution effect of the remnant oil. Encapsulation involves mixing dry produced sand with asphalt concrete mix (approximately 50:50) to generate a low-grade material suitable for roadbed enhancement. It is used as a base course to underlie high-quality asphalt concrete used as a surface course. Approximately 1 m3 of sand per meter length of two-lane roadway can be disposed of in this manner; therefore, it is a limited means of disposal.

Other uses (addition to cement kilns, sand-blasting sand, feedstock for manufacturing processes) involve only small amounts of the total sand produced, and the sand cannot be cleaned economically to meet specifications for use as fiberglass sand or sand blasting. These methods cannot be used as primary disposal approaches for the volumes of sand produced.

Sand Washing. Hot water and surfactant separation has been used to wash sand either for secondary use or for local disposal; however, since 1990, three commercial plants in Alberta have failed financially because of the high cost of dealing with three waste streams (dirty water, dirty oil, and sand) created from a single waste (oily sand). Sand cannot be washed sufficiently clean of oil for use in sand blasting or industrial feedstocks. Despite its superficial attractiveness, sand washing is not advised.

Landfill Placement. Class II landfills for nonhazardous oilfield waste are required for disposal of solids that do not contain draining water. Definitions, guidelines, and other information exist on regulatory agency websites. [66] Landfills are the cheapest of the three disposal methods, but obtaining a license and complying with regulations has not always proved easy. Also, the long-term security of landfills and their proximity to groundwater remain serious concerns, particularly given the difficulty of guaranteeing that all wastes meet guidelines.

Deep Injection of Sand and Fluid Wastes. Large volumes of waste sand can be slurried with dirty produced water that must be disposed of by conventional well injection and fractured at high rates into oil-free zones or depleted reservoirs. [75][76][77] This technique has been used in the U.S., Canada, and Indonesia. [12] The target zone can be a depleted reservoir or a new, oil-free zone. The zone must have adequate flow properties and reservoir capacity to accept 200,000 to 400,000 m3 of slurry of density 1.15 to 1.25 g/cm3 injected over a period of 1 to 3 years. Injection is normally episodic on a daily basis, allowing time for pressure dissipation before another 8 to 12 hours of 0.8 to 1.6 m3/min slurry placement is undertaken. Fig. 5.31 shows a typical pressure-time response.

In addition to high environmental security, another advantage of injecting a slurry is that dirty liquids, sludges, and even some emulsion can be added to the mix and codisposed. A disposal well approved for nonhazardous oilfield waste allows more flexibility in handling the various waste steams. Because disposal costs for produced water may exceed Canadian $7.00/m3, the approximately 4 to 6 m3 of produced water used to slurry each cubic meter of sand represents a cost savings.

Because of cost, some operators have used massive deep injection of pure emulsions. However, this impairs the performance of fracture injection wells, leading to premature casing distress[78] unless carefully executed in conjunction with large volumes of sand.

Salt Cavern Placement. Solution caverns in salt are used in Canada for CHOPS wastes, as well as for other oil industry wastes (e.g., refining sludges from the synthetic crude plants at Ft. McMurray). Trucks transporting wastes dump directly into a hopper, and slurry pumps place the materials into caverns at a depth of 900 to 1200 m. In the cavern, solids (ρ ~ 2.65) drop to the bottom, and oils and emulsions (ρ ~ 1.0) float to the top of the brine (ρ = 1.2) and are removed through the annulus. The cavern acts as a huge gravitational separator for solids and oils. The advantages of salt cavern disposal are similar to those for slurry injection, except that total costs are somewhat higher (~10 to 20%), and excess brine must be disposed in a brine-injection well.

Emulsion, Slops, and Oil Treatment. Slops and emulsion generally are dewatered and sent to caverns, deep-placement injection sites, or special treating facilities that remove water, separate oil and solids, and dispose of the streams. Requirements for emulsion breaking, centrifuge separation, and heat treatment make this processing expensive.

Before shipment to the upgrader or transport by pipeline, produced oil must be heat treated and stripped of remnant solids and water by chemical treatment with surfactants or emulsion breakers. Many companies send intermediate waste streams to permanent disposal facilities rather than pay the high costs of additional treatment or of recycling wastes through local treatment facilities.

Case Histories

Luseland Field, Saskatchewan

A detailed Luseland field case history has been published. [79] It had a long history (12 to 15 years) of slow production with reciprocating pumps, an attempt to produce with horizontal wells (6 wells, all failures), and then a conversion to CHOPS through reperforation and PC pump installation.

Table 5.3 shows basic field parameters. Fig. 5.32 shows the 1982 to 2003 production history of the field. Approximately the same number of wells has been on production since 1984; therefore, the majority of the production increase can be ascribed to flow-rate enhancement as the result of CHOPS. Figs. 5.33 through 5.35 are individual well production plots that show increases of up to 10-fold in oil rates for individual wells. These are not new wells. They are conversions that gradually were operated more aggressively; therefore, they show production histories different from those illustrated in Fig. 5.3. Fig. 5.36 shows a less successful conversion to CHOPS.



In 1998, approximately 10,000 m3 of sand were produced with approximately 200,000 m3 of oil and 120,000 m3 of water. Annual oil production leveled and then declined after 1999. Overall, rates went from 2 to 8 m3/d pre-CHOPS (1991) to 5 to 50 m3/d (average of 21.6 m3/d/well in 1998) for an overall 4.9-fold increase. Expected per-well recovery went from 3 to 8% to 12 to 25% OOIP. [80] Although water production has increased, the water-to-oil ratio (WOR) in 2000 was lower than in 1994. Sand-handling requirements have increased 10-fold as oil production increased approximately 5-fold. In the most productive wells, the GOR has remained roughly constant or climbed only slowly since CHOPS was implemented.

Various operational and workover strategies were changed to cope with sand production. For example, in some cases, 3.5-in. tubing was changed to 4.5-in. tubing to cope with higher torques as sand influx increased. Sand-handling costs dominate operating expenses (> 30%), but because oil production is much higher, unit costs have dropped to less than half [i.e., from Canadian $65 to 80/m3 to $20 to 40/m3 (per-well basis)].

As of 2003, the most productive wells in this field had produced more than 700,000 cumulative barrels of heavy oil, and the average of the original wells has exceeded 250,000 barrels. These are remarkable values for viscous oil produced without thermal stimulation.

Comparisons of Cold Production From Horizontal Wells and CHOPS Wells

Horizontal wells have been used widely for heavy-oil production in the last decade. The question arises: are horizontals, perhaps with multilaterals, better for heavy-oil production? Issues of relative performance, absolute performance, and implementation of follow-on technologies complicate the answer. A limited study was carried out **

in four different fields in which horizontal wells are adjacent to vertical wells (Plover Lake, Lindbergh, Cactus Lake, and Luseland). Table 5.4 presents specific data for the Plover Lake field.


Plover Lake field is a Bakken formation UCSS reservoir similar to the Luseland field in all aspects, except that the average pay is 20 to 25% thinner. Table 5.4 shows the production data for 10 wells (four vertical and six horizontal) from the same section (one square mile).

The horizontal wells first used steam in a line drive from vertical wells to drive oil toward the horizontal producers. The performance of the horizontal wells, even with steamdrive, did not match the performance of the vertical wells in terms of total oil or lifespan. The best of the six horizontal wells produced a total of approximately 157,000 bbl; the best vertical well produced 265,990 bbl and was still producing successfully when the data were collected. The horizontal wells displayed higher WORs, attributed by the operator to the greater odds of proximity to active water. Vertical CHOPS wells in other areas of this field generally have performed even better.

Lindbergh field is a thin (4 to 8 m), Cretaceous, heavy-oil field with approximately 10,000 cp viscosity oil in fine-grained 30% porosity sand approximately 600 m deep. Fig. 5.37 presents a sample plot of production from the Lindbergh field for a vertical well, and Fig. 5.38 presents a sample plot of production from the Lindbergh field for a horizontal well. These are new wells, not converted wells. When all costs are considered, it appears that in most heavy-oil fields in which the viscosity is less than 15,000 cp, CHOPS is far more profitable than horizontal wells.

In Plover Lake field as well as Lindbergh and Luseland fields, attempts to achieve cold production from horizontal wells were economic failures, but in fields with different geology and lower viscosity (e.g., Cactus Lake, Amber Lake, Pelican Lake), horizontal wells have been successful. However, when the economics are compared carefully, it appears that CHOPS vertical wells provide more total oil (albeit more slowly), lower capital expenditures, and lower WORs. For example, in Pelican Lake and Amber Lake fields, production declines for 1000-m-long horizontal wells have been 35 to 45%,[81] indicating a short well life.

Monitoring CHOPS

Monitoring Produced Fluids and Well Behavior

To track and understand well behavior adequately, data that are more precise than the averaged data from stock-tank measurements is needed.

Sand content can be variable on any time scale. To examine this chaotic behavior, 500-mL flowline samples are taken. To obtain an averaged value, a 20-L pail is used, and 500-mL samples from the same well are added over time until approximately 5 L are available (10 to 15 samples). The gas is allowed to evolve before water, oil, and sand contents are determined. Standard oilfield methods are used (dilution with solvents, centrifuging, etc.) for solids and water contents.

Determining gas content is more difficult because gas is produced through the annulus as well as the tubing. Gas content measurements on flowline samples are straightforward: vacuum bottles are used to collect samples that are sent to a laboratory for analysis. The low-pressure gas exiting through the annulus can be metered (although this is still rare), and the two values corrected and combined to give an average gas content. In the absence of reliable gas information from which solubility can be calculated, a value for methane of 0.20 v/v/atm has been found to be widely consistent for heavy oil.

Long-term averages for sand, water, and oil volumes can be estimated from the stock-tank levels and transportation information. However, care must be taken in sand-volume estimation because it is easy to be in error by 10 to 15%, particularly if thick emulsions are involved. Installation of a BHP gauge on the tubing is advised, as well as continuous monitoring of both annulus pressure and pressure at the top of the pump. These data streams can be used directly in computer programs that optimize pumping, maintaining the fluid annulus at the desired level. Operating data for the pump (rev/min, torque) are used along with BHP data to ensure optimal pump operation.

Fieldwide Monitoring Approaches

Little full-field monitoring of CHOPS has occurred because of the low profit margins. However, the incentive to collect data for infill drilling and reservoir management is increasing, whereas costs for collecting data are decreasing.

Active seismic methods (3D seismic imaging), used by PanCanadian Petroleum, have identified large zones of low seismic velocity and large attenuation (Fig. 5.23), as well as interwell areas where depletion has not occurred. Passive seismic monitoring involves listening to seismic emissions generated by production processes. Because geophones are located in the reservoir, wave travel distances are short, and low-magnitude events are easily registered. This method has been used to track fireflood fronts[82] and, more recently, to monitor activity in the reservoir during pressure pulsing in an excitation well. In the latter case, an increasing incidence of interwell shear events indicated that the pulsing had the effect of destabilizing the interwell region, allowing access to undepleted pressures. Microseismic monitoring has promise as a method of helping field management. Well testing is not a useful practice in CHOPS fields: interference phenomena, rate effects, etc. cannot be analyzed with existing theories.

CHOPS and Other Production Technologies


CHOPS is not suitable for all heavy UCSS reservoirs. Recovery factors greater than 20% of OOIP are unusual; values of 10 to 16% are more common. However, combining CHOPS with other production technologies may increase ultimate recovery factors.

Hybrind Production Schemes

Through yield, dilation and liquefaction, and perhaps through channeling, CHOPS creates a large region of greatly enhanced permeability. Is it possible to exploit this with other technologies?

Fig. 5.39 shows a possible scheme of simultaneous development of a reservoir for CHOPS and SAGD. [83][84] The reservoir is at least 15 to 20 m thick. The recommended well spacing is approximately 5 times the reservoir thickness. CHOPS is started well before SAGD. The permeability-enhanced zone develops upward toward the top of the zone. SAGD wells are started after CHOPS has produced 12 to 14% of OOIP, then operated to maximize lateral migration of the steam chamber. When heat breakthrough occurs in a CHOPS well, the PC pump is removed and it is shut in. The high permeability should allow the SAGD process to access and exploit the oil in the reservoir quickly. After all, the natural limit on SAGD rate is the formation permeability. The CHOPS wells are converted to monitoring wells or process-control wells for inert gas injection or partially miscible gas placement (hybrid CHOPS-VAPEX-SAGD scheme). Clearly, many issues such as placement of perforations, repressurization approaches with the CHOPS wells (inert gas, miscible gas, hot water, steam), and details of sequencing must be addressed in practice.

Similarly, CHOPS can be combined with VAPEX and THAI. In all cases, enhanced permeability, high compressibility, and low lateral stress generated by CHOPS can be exploited, in principle, to increase production with horizontal well approaches.

CHOPS probably can never be used subsequent to other recovery schemes if the reservoir has been depleted of gas. Also, if a thermal process has been used, not only is gas depleted, but mineral and coke cementation also may have occurred, giving the sands enough cohesion to resist attempts at CHOPS.

However, in many cases, such as the Luseland example (see Sec. 5.9.1), slow conventional production with some sand ingress was converted successfully to CHOPS. Whether this could ever be done successfully for horizontal wells (see Sec. 5.9.2) is uncertain because of well-cleaning costs, but CHOPS may be used in zones left untouched by drawdown from horizontal well production.

CHOPS is more suitable for use before other approaches. For example, cyclic steam-stimulation recovery factors are, at most, 20 to 25% of OOIP, but if CHOPS is used first, the low σh, high k, and high Cm zone will promote a far better conformance than CSS normally achieves. After a 15% CHOPS phase, the CSS process could produce an additional 15 to 20% of OOIP. After CHOPS, CSS should be successful because steam fractures will be better contained and "recompaction" drive[85] enhanced because of the presence of the large remolded zone.

Pressure Pulse Flow Enhancement

Continuous pressure pulsing has been used to sustain production of heavy oil through CHOPS. This new approach involves continuous high-amplitude but low-frequency excitation of the liquid phase in an excitation well. [86] Although the database is still limited, all three excitation well cases completed to date have been economic successes. The aggressive pressure pulses sustain sand flux to offset wellbores, destabilize the interwell regions so that vertical stresses yield and dilate sands through shear, and overcome permeability channeling and perhaps collapse open channels so that conformance is improved.

Can Heavy-Oil Fields Be Successfully Waterflooded?

Despite a seemingly intractable mobility ratio (> 1,000), waterflooding has been used in heavy oil in Canada. Apparently, given the low cost of wells, enough maintenance of oil rate takes place to justify the practice because only a few percent (1 to 4% OOIP) additional oil is produced in this manner toward the end of a CHOPS project.

Waterflooding recently has been used along with aggressive pressure pulsing. 7 The inertial energy introduced by the pulsing helps overcome capillary blockages as well as reduces viscous fingering associated with water injection. This has assisted in stabilizing waterflood front conformance and increasing sweep efficiency.

Extension of CHOPS Concepts to High-Rate Oil and Gas Wells

Sand management principles that evolved from CHOPS were used in 1995 in modest offshore Adriatic Sea gas wells[87] and later in offshore North Sea high-rate oil wells. [88] In these cases, sand is not excluded. Wells are operated with small irregular sand bursts, properly managed to reduce risk. These wells are cheaper to complete and average 35 to 40% greater production than adjacent wells with gravel packs or sand screens. Preliminary well histories also suggest that intervention costs are reduced. The penalty for these economic benefits is required continuous monitoring and analysis, but in more than 200 wells with production rates as high as 4500 m3/d, there is only one outright failure of the method that required the use of sand exclusion methods.

Fig. 5.40 summarizes sand management principles. Two limits are shown: the sand-free line for rate vs. sand strength and an upper limit of either catastrophic sanding or facilities limitations. Sand 1 is the weakest sand in the stratum. It controls the production rate for "stable" sand bursts, which cause no well problems because they tend to decay and rarely recur. If the weakest sand is also a thin sand in the context of the producing interval, selective perforating can isolate it and perhaps generate additional production improvements (as for Sand 2).

Part of sand management is a sand-cleanup test, which is a protocol for aggressive well cleanup that deliberately surges the well at increasing flow rates until a sand burst enters. These bursts are not catastrophic well-blocking events; rather, they serve to unblock perforations and flush out wellbore fines or mineral blockages, thereby reducing mechanical skin effects. A well may have skin values of +5 to +10 before cleanup and values as low as −3 to −5 after cleanup. Effects on the productivity index are appreciable. Because the well is maintained on higher production rates after the cleanup, occasional sand bursts (5 to 50 kg) can take place every few days or weeks. These sand bursts are self-cleaning events that help sustain the low skin values.

The benefits of higher production rates, lower completion costs, and fewer interventions are substantial, but various design issues such as sand-influx detection and steel erosion have to be addressed. Another important advantage is that sand-management strategies do not ruin the well for later installation of sand-control methods (screens, gravel packs, etc.), whereas the reverse is almost never true, especially if there are behind-the-casing installations involving resin-coated sand. Thus, if sand management is not successful, the risk to the well life is minimal. Assessment of a well for sand management is a complex task requiring calculations of carrying capacity, erosive resistance of the production system, capacity to handle sand, and so on. [89]

Summary of CHOPS


There are several important facts about this heavy-oil production method:

  • In UCSS reservoirs with good solution-gas quantities, no cohesion, and viscous oil, sand influx is initiated and sustained to take advantage of huge increases (3-fold to 20-fold) in "primary" production rate, as compared with cold production with sand exclusion.
  • Rate increases are associated with sand liquefaction, permeability increase, foamy oil mechanisms, and elimination of near-wellbore fines and asphaltene blockage.
  • Ultimate recovery factors have improved from 2 to 6% to 12 to 20% of OOIP in many heavy-oil fields with the use of CHOPS.
  • Between 1985 and 2002, great improvements have been seen in handling sand, maintaining wells on sand production, lifting efficiency, and other aspects of CHOPS.
  • Operating expenses have been cut almost in half between 1989 and 2002, while the total CHOPS production rate has more than tripled. CHOPS concepts are beginning to affect conventional oil and gas production approaches in suitable reservoirs.
  • Given the vast heavy-oil resources and the inevitable depletion of conventional oil, technologies such as CHOPS will steadily become more important



* Rothenburg, L., Bratli, R.K., and Dusseault, M.B.: "A Poro-Elastic Solution for Transient Fluid Flow Into a Well," available from Dusseault on request (1996).**

El-Sayed, S. and Dusseault, M.: unpublished data and report (2000).

Nomenclature


A = cross-sectional area, L2
Av = specific surface, 1/L, m2/m3 (area per unit volume)
c = mechanical cohesion, m/Lt2, kPa or MPa
C = °C, T
Cm = rock matrix compressibility, Lt2/m, kPa−1
Co = shape factor
F = hydrodynamic seepage force on a grain, mL/t2, kN
g = gravitational acceleration, L/t2, 9.81 m/s2
Go = specific gravity of oil with respect to 1.0 (water)
Gs = specific gravity of solid (mineral) with respect to 1.0 (water)
Gw = specific gravity of water with respect to 1.0 (water)
h = height, L, m
k = permeability, L2, darcy
k1, k2, k3 = permeability of specific regions, L2, darcy
kg = relative permeability to gas (ratio of k)
ki = near-field (altered) permeability, L2, darcy
ko = far-field (unaltered) permeability, L2, darcy
kp = permeability of the sand-fluid mixture
kr = radical permeability, L2, darcy
kw = relative permeability to water (ratio of k)
l = length vectors, L, m
mo = mass of oil, m, grams or kilograms
ms = mass of solid (mineral matter), m, grams or kilograms
mw = mass of water, m, grams or kilograms
N = number of flow channels in a unit volume around a CHOPS well, 1/L3
P = pressure, m/Lt2, kPa or MPa
pb = bubblepoint pressure, m/Lt2, kPa or MPa
pf = pressure in a fluid, m/Lt2, kPa or MPa
pi = interior pressure (as in a borehole or liquefied zone), m/Lt2, kPa or MPa
po = initial pressure or unaltered far-field pressure, m/Lt2, kPa or MPa
Q = production rate, L3/t, m3/d
Qo = initial production rate, L3/t, m3/d
r = radius (from the center of a circular opening or well), L, m
r1, r2, r3 = specific radial distances, L, m
ro = initial effective well radius before sanding, L, m
rw = wellbore radius, L, m
S = grain shape factor, a fractional quantity less than 1.0
Sg = gas saturations, fraction (< 1.0) or percent of pore volume
So = oil saturations, fraction (< 1.0) or percent of pore volume
Sw = water saturations, fraction (< 1.0) or percent of pore volume
v = velocity, L/t, m/s
vD = Darcy velocity, L/t, m/s
vf = fluid velocity, L/t, m/s
vs = solid (mineral) velocity, L/t, m/s
V = volume, L3, m3 or cm3
Vg = volume of gas, L3, m3 or cm3
Vo = volume of oil, L3, m3 or cm3
Vs = volume of sand, L3, m3 or cm3
Vt = total volume, L3, m3 or cm3
Vw = volume of water, L3, m3 or cm3
w = grain width, L, m or mm
z=depth, L, m
γ¯ = mean overburden unit weight, m/L2t2, kN/m3
Δp = pressure drops
ΔQ = change in rate
ΔT = change in temperature
ΔV = change in volume
Δσ = change in effective stress
μ = viscosity, m/Lt, cp
ρ = density, m/L3, g/m3
ρ¯ = mean density, m/L3, g/m3
φ = porosity, %
σ = stress, m/Lt2, MPa
σh = horizontal (lateral) stress, m/Lt2, MPa
(σh)min = minimum horizontal stress, m/Lt2, MPa
(σh)max = maximum horizontal stress, m/Lt2, MPa
σmin = minimum stress (any direction), m/Lt2, MPa
σr = radial stress, m/Lt2, MPa
σv = vertical stress, m/Lt2, MPa
σθ = tangential stress, m/Lt2, MPa
σ = effective (matrix) stress, m/Lt2, MPa
σ′h = effective horizontal stress, m/Lt2, MPa
σ′n = effective normal stress, m/Lt2, MPa
σ′r = effective radial stress, m/Lt2, MPa
σ′v = effective vertical stress, m/Lt2, MPa
σ1 = major principal stress, m/Lt2, MPa
σ2 = intermediate principal stress, m/Lt2, MPa
σ3 = minor principal stress, m/Lt2, MPa
τ = tortuosity, 1/L

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General References


Cold Heavy Oil Production with Sand, U. of Waterloo, Ontario, Canada, http://sciborg.uwaterloo.ca/research/chops.

SI Metric Conversion Factors


°API 141.5/(131.5 + °API) = g/cm3
atm × 1.013 250* E + 05 = Pa
Bbl × 1.589 873 E – 01 = m3
cp × 1.0* E – 03 = Pa•s
Ft × 3.048* E – 01 = m
ft2 × 9.290 304* E – 02 = m2
ft3 × 2.831 685 E – 02 = m3
°F (°F − 32)/1.8 = °C
hp-hr × 2.684 520 E + 00 = MJ
in. × 2.54* E + 00 = cm
bm × 4.535 924 E – 01 = kg
mile × 1.609 344* E + 00 = km
psi × 6.894 757 E + 00 = kPa


*

Conversion factor is exact.