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CHOPS reservoir assessment and candidate screening
Evaluation of reservoirs as candidates for cold heavy oil production with sand (CHOPS) requires an assessment of the reservoir and an understanding of the key success factors for this technology. This article discusses what is known in these areas.
- 1 Typical reservoir characteristics
- 2 Coring and logging unconsolidated heavy-oil sands
- 3 Determining material parameters for screening and simulation
- 4 Field testing for CHOPS assessment
- 5 Screening criteria for CHOPS projects and wells
- 6 Nomenclature
- 7 References
- 8 Noteworthy papers in OnePetro
- 9 External links
- 10 See also
- 11 Page champions
- 12 Category
Typical reservoir characteristics
The range of reservoir characteristics for CHOPS comes largely from Canadian experience. Table 1 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. 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 unconsolidated sandstone (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), 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
for phase volumes and
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.
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. One version, in which permeability is related to porosity, φ , specific surface, Av, tortuosity, τ, and a shape factor, Co, is
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 vapor-assisted petroleum extraction (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.
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, 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. 1 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. 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; nevertheless, the cohesion intercept in a Mohr-Coulomb shear-failure criterion plot 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. 2 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. 3), 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.
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 Operational issues in cold heavy-oil production with sand (CHOPS)).
- 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.
The reservoir interval must be unconsolidated sandstone (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.
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.
Oil saturation should be high, preferably So > 0.80, although a few exceptions to this are known in Canada (see CHOPS case histories). 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.
|Av||=||specific surface, 1/L, m2/m3 (area per unit volume)|
|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)|
|k||=||permeability, L2, darcy|
|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|
|vs||=||solid (mineral) velocity, L/t, m/s|
|Vo||=||volume of oil, L3, m3 or cm3|
|Vs||=||volume of sand, L3, m3 or cm3|
|Vt||=||total volume, L3, m3 or cm3|
- Dusseault, M.B. 2001. Comparing Venezuelan and Canadian Heavy Oil and Tar Sands. Presented at the Canadian International Petroleum Conference, Calgary, Alberta, Canada, 12–14 June. CIPC 2001-061. http://dx.doi.org/10.2118/2001-061.
- Dusseault, M.B. 1980. Sample Disturbance In Athabasca Oil Sand. J Can Pet Technol 19 (2). PETSOC-80-02-06. http://dx.doi.org/10.2118/80-02-06.
- Dusseault, M.B. and Rothenburg, L. 1988. Shear Dilatancy and Permeability Enhancement in Oil Sands. Proc., 4th Unitar Conference on Heavy Crude and Tar Sands, 3, 55–6.
- Dusseault, M.B. and Morgenstern, N.R. 1978. Shear Strength of Athabasca Oil Sands. Canadian Geotechnical J. 15 (2): 216.
- Geilikman, M.B., Dusseault, M.B., and Dullien, F.A. 1994. Sand Production as a Viscoplastic Granular Flow. Presented at the SPE Formation Damage Control Symposium, Lafayette, Louisiana, 7-10 February 1994. SPE-27343-MS. http://dx.doi.org/10.2118/27343-MS.
- Geilikman, M.B., Dusseault, M.B., and Dullien, F.A.L. 1994. Sand Production and Yield Propagation Around Wellbores. Proc., CIM Petroleum Society 45th Annual Technical Meeting, Calgary, paper 94-89. 34.
- Geilikman, M.B., Dusseault, M.B., and Dullien, F.A.L. 1994. Fluid-saturated solid flow with propagation of a yielding front. Presented at the Rock Mechanics in Petroleum Engineering, Delft, Netherlands, 29-31 August 1994. SPE-28067-MS. http://dx.doi.org/10.2118/28067-MS.
- Geilikman, M.B., Dusseault, M.B., and Dullien, F.A.L. 1995. Dynamic Effects of Foamy Fluid Flow in Sand Production Instability. Presented at the SPE International Heavy Oil Symposium, Calgary, Alberta, Canada, 19-21 June 1995. SPE-30251-MS. http://dx.doi.org/10.2118/30251-MS.
- Geilikman, M.B. and Dusseault, M.B. 1997. Fluid-Rate Enhancement from Massive Sand Production in Heavy Oil Reservoirs. J. of Petroleum Science & Engineering 17: 5.
- Geilikman, M.B. and Dusseault, M.B. 1997. Dynamics of Wormholes and Enhancement of Fluid Production. Proc., CIM Petroleum Society 48th Annual Technical Meeting, Calgary, paper 97-09.
Noteworthy papers in OnePetro
Rangriz Shokri, A., & Babadagli, T. 2012. Evaluation of Thermal/Solvent Applications With And Without Cold Heavy Oil Production with Sand (CHOPS). Society of Petroleum Engineers. http://dx.doi.org/10.2118/158934-MS
Babadagli, T., & Rangrizshokri, A. 2013. Modeling Thermal and Solvent Injection Techniques as Post-CHOPS Applications Considering Geomechanical and Compositional Effects. Society of Petroleum Engineers. http://dx.doi.org/10.2118/165534-MS
Meza-Diaz, B., Tremblay, B., & Doan, Q. 2003. Mechanisms of Sand Production Through Horizontal Well Slots in Primary Production. Petroleum Society of Canada. http://dx.doi.org/10.2118/03-10-04
Meza-Díaz, B. I., Sawatzky, R. P., Kuru, E., & Oldakowski, K. 2011. Sand on Demand: A Laboratory Investigation on Improving Productivity in Horizontal Wells Under Heavy-Oil Primary Production. Society of Petroleum Engineers. http://dx.doi.org/10.2118/115625-PA
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