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Tight gas drilling and completion
The definition of a tight gas reservoir is that the reservoir does not produce at commercial gas flow rates, or recover commercial volumes of natural gas, unless a hydraulic-fracture treatment is properly designed and pumped. As such, the entire drilling and completion procedures should focus on making sure the optimum fracture treatment can be designed and pumped in the field.
When drilling a tight gas well, the most important aspect of the drilling operation is to drill a gauge hole. Many times this means the well should be drilled at a balanced mud weight or slightly overbalanced. In other cases, air drilling or underbalanced drilling works best, as long as the hole remains in gauge. If a gauge hole is drilled, we can run openhole logs and obtain valid data that are required to properly evaluate the formation and to design the completion. If the hole is washed out and rugose, the logs are difficult or impossible to accurately evaluate, and the net gas pay is difficult to identify. Also, if the borehole is in gauge, the chances of obtaining a satisfactory primary cement job on the production casing increase when compared to trying to cement casing in a washed-out borehole. Obtaining a good primary cement job is extremely important when completing a well in a multilayered reservoir that must be fracture treated.
Some drilling personnel want to drill underbalanced in tight gas reservoirs because:
- The penetration rate is faster
- Formation invasion of mud filtrate is minimized
- There is little chance of a gas kick because of the low permeability nature of the formations
However, underbalanced drilling is only acceptable if a gauge hole can be maintained. Speed to reach total depth is not important if the borehole is washed out and we cannot properly evaluate the reservoir layers or obtain an adequate primary cement job. Also, formation damage is not an important consideration in tight gas reservoirs. It does not matter whether or not the near-wellbore formation has been damaged during drilling. In every case, we still use multiple pump trucks and pump rather large fracture treatments. The hydraulic fracture breaks through any near-wellbore damage.
To complete a tight gas well successfully, the engineer should consider the items included in Table 1. The ideal completion is the one that produces the most gas for the lowest cost—considering both the initial completion cost and the subsequent operating costs. This definition implies that a prudent engineer will attempt to provide a functional completion for many years to come at the lowest possible cost to the operator.
Of concern in the design of the completion is always the number of producing zones that are separated in the reservoir by vertical flow barrier layers. To determine whether different producing intervals should actually be treated as a single reservoir, one must first determine if these various intervals are all connected by a single hydraulic fracture. If a particular zone is separated from another pay zone by a thin silt or shale layer with little in-situ stress contrast among the layers, one can use a model to determine if all the zones can be connected by a single hydraulic fracture. If a single fracture treatment is used to stimulate multiple layers, and no reservoir damage occurs by commingling the different zones, the well should be completed as if all the layers are actually a single reservoir. Normally, in dry gas reservoirs, no reservoir damage occurs by commingling zones. In fact, it is likely that more gas will be recovered by producing all the layers commingled because the abandonment pressure is lower at any given economic limit when the zones are commingled vs. producing the zones one at a time.
If two or more productive intervals are separated by a thick, clean shale (say, 50 ft or more) and this shale has enough in-situ stress contrast to be a barrier to vertical fracture growth, the design engineer might need to design the completion and stimulation treatments to consider the fact that multiple hydraulic fractures will be created. In such cases, fracture treatment diverting techniques must be used to properly stimulate all producing intervals. More information concerning completion design in multilayered reservoirs is available in the technical literature.
The two main concerns with tubular design are pumping the optimum fracture treatment and liquid loading as the gas flow rate declines. These two concerns must be balanced to achieve the optimum well completion. As previously stated, a tight gas well is uneconomic to drill, complete, and produce unless a successful fracture treatment is designed and pumped. In general, fracture treatments are more successful when pumped at higher injection rates. Therefore, to pump a treatment at a high injection rate, we normally like to use large tubulars.
Once the treatment is pumped and the well is put on production, the gas flow rate begins to decline. All wells, even dry gas wells, produce liquids in the form of condensate or water. Regardless of how little liquid is produced, the well eventually loads up with liquids as the flow rate declines. Liquid loading is a function of gas velocity. Therefore, to minimize liquid-loading problems, we must use small tubing.
Thus, the dilemma: we need large tubulars to pump the fracture treatment and small tubulars to minimize liquid loading. The solutions to this dilemma can be as varied as the number of fields in which we work. Many considerations and computational techniques needed to solve these problems are presented in Gidley. In some cases, when the reservoir pressure is at or below normal pressure, we can fracture treat the formation down casing, then run small tubing after the treatment to produce the well. If the reservoir is geopressured, we might have to fracture treat the well down tubing at injection rates less than optimum.
The topic of how to design casing and tubing and how to design the optimum tubular configuration in a tight gas well is too large to deal with completely in this chapter. The completion engineer should, however, try to design the fracture treatment and the completion prior to spudding the well. If, during the design, the engineer determines that a certain size casing or a certain size tubing is required to implement an optimal design, the completion engineer should provide that feedback to the drilling engineer. The drilling engineer can then design the bit program and casing program to accommodate the needs of the completion engineer. Once the hole is drilled and the production casing is set and cemented, it is too late to redesign the completion if you discover you needed larger casing to implement the optimum completion.
In the same manner, the fracture treatment should be designed prior to spudding the well, so a reasonable estimate of fracture treatment pressures, from bottomhole to the surface, can be estimated as a function of:
- The casing size
- The injection rate
- The fracture fluid friction and density properties
It is very important to know the maximum injection pressure during the fracture treatment for a variety of completion scenarios. The drilling engineer can use that information to select the correct size, weight, and grade of casing. A fracture treatment is usually not successful if the injection rate or fluid viscosity is compromised when the casing cannot withstand the desired injection pressure. Again, working the problem prior to spudding and designing the casing correctly can prevent problems and allow the service company to actually pump the optimum fracture treatment.
Perhaps the least understood part of well completions and hydraulic fracturing revolves around how to perforate a well. Again, there is no simple solution, and the best perforating scheme varies depending on the specific reservoir situation. Two factors seem to be very important. First, the number of layers and the number of fracture treatment stages affect how we perforate the well. Second, the in-situ stress anisotropy plus the presence or lack of natural fractures have a strong bearing on how we perforate the well.
A problem associated with hydraulic fracture treatment problems has been recently identified in the petroleum literature as "near-wellbore tortuosity." Near-wellbore tortuosity occurs when multiple hydraulic fractures are created near the wellbore. These multiple hydraulic fractures are usually caused by the presence of natural fractures or the fact that too many perforations are shot in multiple directions over a long, perforated interval. When multiple fractures occur near the wellbore, each fracture is narrower than a single fracture, and problems occur when trying to pump the propping agent down the narrow fractures. In many cases, a near-wellbore screenout occurs when near-wellbore tortuosity problems occur.
There are several ways to minimize near-wellbore tortuosity problems. The best solution might be to minimize the length of the perforated interval and to orient the perforations 180° in the same direction that the fracture propagates (which is perpendicular to the minimum principle horizontal stress, for a vertical fracture). More information concerning stresses and stress orientations is found in Gidley.
Again, the main concern when perforating a tight gas well is to perforate in such a way that the optimum fracture treatment(s) can be successfully pumped. The completion engineer must be concerned with choosing the correct zones and perforating those zones to accommodate any diversion techniques that will be used in multistaged fracture treatments.
In the perforating literature, there are many papers discussing how many holes are needed per foot of casing so that the productivity index is not reduced because of too few holes. In a tight gas well that is fracture treated, the number of holes per foot of casing is really not much of a consideration. More importantly, the number of holes with respect to the fracture treatment injection rate should control the perforation operation. A good rule of thumb is that the number of holes should be such that the injection rate per hole is between 0.25 and 0.5 barrels per minute per perforation. For example, if you plan to pump the fracture treatment at 20 barrels per minute, then you should consider putting between 40 and 80 holes in the pipe in the zone where you want the fracture to initiate. In general, the more compact the perforated interval the better, and perforations oriented 180° in the direction of maximum horizontal stress provide the best situation for hydraulic fracturing. The worst situation is to shoot 4 or 6 shots per foot over a long interval. When too many holes are shot over too long an interval, the engineer loses control of where the fracture initiates, and the chances of creating multiple fractures at the wellbore increases substantially.
- Gidley, J.L. et al. 1989. Recent Advances in Hydraulic Fracturing, 12, 245-262. Richardson, Texas: Monograph Series, SPE.
- Rahim, Z. and Holditch, S.A. 1995. The Effects of Mechanical Properties and Selection of Completion Interval Upon the Created and Propped Fracture Dimensions in Layered Reservoirs. J. Pet. Science & Eng. 13: 29.
- Cleary, M.P., Johnson, D.E., Kogsbøll, H.-H. et al. 1993. Field Implementation of Proppant Slugs To Avoid Premature Screen-Out of Hydraulic Fractures With Adequate Proppant Concentration. Presented at the Low Permeability Reservoirs Symposium, Denver, Colorado, USA, 26–28 April. SPE-25982-MS. http://dx.doi.org/10.2118/25892-MS.
Noteworthy papers in OnePetro
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read
Cox, Stewart. 2013. Effects of Complex Reservoir Geometries and Completion Practices on Production Analysis in Tight Gas Reservoirs. https://webevents.spe.org/products/effects-of-complex-reservoir-geometries-and-completion-practices-on-production-analysis-in-tight-gas-reservoirs-spe-distinguished-lecturer
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