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Forecasting gas production
This page explores the fundamental relationships underlying gas reservoir performance and presents some simple techniques for forecasting production rate vs. time.
One way to envision the different factors affecting the performance of a gas reservoir is to define the production "system" with three components:
- Well deliverability
- Wellbore hydraulics
- Production equipment constraints
Rate vs. time behavior is governed by the combined effect of these three parts, which in turn have performance characteristics that vary with pressure and production rate. Wellbore and system constraints include:
- Tubing and choke sizes
- Amount of entrained liquids (condensate and water)
- Accumulation of sand or debris in the wellbore
- Flowline pressure drops
- Compression ratios across compressors
- Pressure losses in separators
If these relationships are plotted on the same presentation, the resulting graph will look like Fig. 1.
At low flow rates, the equipment-performance curve is nearly horizontal, reflecting the small flowing frictional pressure drops in the system. If there is liquid holdup in the production tubing, multiphase-flow calculations can show the curve bending upward at low production rates.
The curves represent maximum performance with existing completion, well, and equipment configurations. At any time, of course, it is possible to operate a well below its maximum performance characteristics by adjusting such things as a choke size at the wellhead. Because this is effectively a "zero-expense" change, it represents how a system is "tuned" to operate at some predetermined rate or other operating condition. Any of the following actions can change the performance curves:
- Perforating additional producing intervals
- Using stimulation treatments
- Lowering separator pressure
- Installing compressors, larger flowlines, and/or production tubing
The concave downward lines (flow rate increasing with decreasing well pressure) are the well-performance curves for different average reservoir pressures. Note that the value of well flowing pressure at zero flow rate is the average reservoir pressure and that the value of flow rate at zero well flowing pressure is the AOF. As reservoir pressure declines, of course, the well-performance curves move down and to the left. These curves may be altered by operational changes that affect well deliverability. Such processes as hydraulic fracturing, acidizing, or reperforating will increase well productivity and move up the AOF point.
The intersection of the equipment- and well-performance curves represents the operating point of the well at a given value of average reservoir pressure. Note that if the equipment-performance curve represents maximum (full-open choke) performance, then the intersection point also represents maximum rate performance.
The intersection points of the well- and equipment-performance curves can be used to construct a relationship between average reservoir p/z and maximum well deliverability such as that shown in Fig. 2. This curve represents the rate that the combined well and equipment design is capable of delivering at any particular average reservoir pressure. Note that this curve can be used to determine the abandonment p/z by knowing the economic limit (i.e., the minimum economic rate).
For the purposes of forecasting total reservoir performance, it is necessary to develop a graph such as Fig. 2 for the reservoir and not just for an individual well. One way to do this is to construct individual graphs for each well and then to add up the flow rates for each well at a given value of average reservoir p/z. Alternatively, one could construct the graph for an average well in the reservoir and then simply multiply by the total number of wells.
Another method would be to first determine reservoir deliverability constants a and b (that is, a and b should represent the following deliverability equation for the reservoir):
where qR is the total reservoir production rate.
There are many ways to develop this sort of relationship, including an analysis of reservoir performance in the same manner as well performance. A simple way would be to obtain and for the individual wells in the reservoir, and then, by assuming that the average well produces at the total reservoir rate divided by the number of wells, nw,
This equation could then be used with an average well-equipment-performance curve.
Through material-balance relationships, it is possible to evaluate expected reservoir pressures knowing cumulative production (see Gas in place and recoverable volumes. The material-balance equation combined with the reservoir deliverability relationship thus leads to a set of two relationships that must hold simultaneously:
For simple gas reservoir situations, it is possible to solve these two relationships either graphically or computationally.
Consider, for example, a typical gas reservoir production scenario in which the reservoir is first put on production at some fixed reservoir rate for an extended period of time. This fixed rate may result from sales-contract considerations or limitations on processing equipment and pipelines. Let qc denote the fixed initial reservoir production rate and tc denote the time of the fixed-rate period.
It is possible to use the reservoir deliverability and p/z material-balance curves to determine the length of the constant-rate period given the rate or vice versa. First, consider how to determine the time.
For a given rate, the reservoir deliverability curve can be used to determine the lowest reservoir p/z that will deliver this rate. Because the reservoir deliverability curve represents the maximum reservoir deliverability before the end of the constant-rate period, the reservoir will be produced at less-than-maximum rates. The value of p/z at the end of the constant-rate period can be entered into the p/z material-balance plot to determine Gpc at the end of the constant-rate period. The constant-rate time period is then
For instance, refer to Fig. 3, where reservoir deliverability and Gp vs. p/z are plotted. If rates from the field were limited to 40 Bscf/yr by contract, equipment, or pipeline limitations, then the lowest p/z that will support this rate is equivalent to a cumulative production of 400 Bscf. The period of constant production would be 10 years.
Similarly, other rates can be selected and equivalent periods of production calculated to develop the inset curve in Fig. 3.
These procedures should be based on average sustainable rates that account for down time and other factors that reduce the composite well deliverability. Care also should be taken to account for the normal "ramp-up" of production that occurs during development drilling.
At the end of the constant-rate period, the reservoir will, barring well or equipment changes, go on decline. At this point, the reservoir will produce at its maximum rate according to the reservoir-deliverability curve. A simple procedure can be used to forecast this period as well by discretizing future production into increments.
Consider that a prediction will be made by discretizing the future cumulative gas produced in an increment ΔGp. Over the time period that this amount of gas is to be produced, there will be some average flow rate . The time to produce the incremental gas production can be approximated by
Assume that qj is the flow rate at the end of the time increment, and qj–1 is the flow rate at the beginning of the time increment. Approximating the average flow rate during flow period j as
Total time since the beginning of the decline period is determined by
The above procedures can be used to evaluate different reservoir-development scenarios. For example, infill drilling or adding compressors would improve the reservoir-deliverability relationship (and thus change the forecast) by sustaining or increasing early-time production but causing the reservoir to have a steeper decline. Whether this would be desirable would depend on economic considerations.
These procedures also suggest ways that past reservoir performance may be evaluated. For example, a historical reservoir-deliverability curve can be generated by plotting reservoir p/z vs. qR during the decline period. This curve could then be adjusted for changes in operating equipment to determine future performance characteristics.
If a gas reservoir is under waterdrive conditions, there is an additional requirement to forecast the amount of water influx to be expected. The difficulty in performing water-influx calculations for most reservoir situations is in knowing the performance characteristics of the aquifer. As mentioned before, computer models ranging from simple to very complex are now available for general use and represent the best method of predicting the amount and timing of water influx. The models also allow investigation of the effects of varying aquifer size and rock characteristics. Matching of performance data will significantly improve the reliability of model projections.
The options discussed before for depleting retrograde-condensate reservoirs are:
- Produce by depletion
- Recycle processed produced gas
- Recycle processed produced gas plus other makeup gas
- Inject N2 or other inert gas
- Waterdrive or injected water
With straight depletion, a considerable amount of the heaviest and most valuable hydrocarbons will be left in the reservoir. Also, reservoir fluids passing through the low-pressure region around the wellbore experience retrograde condensation, resulting in a large liquid saturation buildup and a significant decrease in gas permeability. This is important from at least two standpoints. First, the composition history of produced fluids early in the life of the reservoir may diverge from predictions that assume uniform pressure in the reservoir at any instant of time. Second, and more importantly, well deliverability will be decreased significantly, affecting both timing and ultimate recovery. Wells can even cease to produce in reservoirs with permeabilities less than 10 md. The effects of liquid buildup on well deliverability need special consideration in low-permeability environments.
Recycling of gas aids recovery from condensate reservoirs in two ways. First, reservoir pressure is maintained, if not above the dewpoint, at least at pressures that minimize liquid deposition. If makeup gas is injected, it is, of course, possible to never go below the dewpoint pressure. The economics of recycling produced gas must weigh the additional recovery benefits against the additional handling and injection costs, the deferred revenue of recovered injected gas, and the lost revenue of injected gas that will remain in the reservoir. These factors make most hydrocarbon gas-injection schemes uneconomical if a gas sale is possible. But where gas sales are to be delayed for many years (e.g., Prudhoe Bay), the resulting economics support a cycling program.
If, however, reservoir pressure has dipped below the dewpoint pressure, injected lean gas can also serve to revaporize a significant part of the deposited condensate because of phase-behavior effects. There has been some interest in the use of N2 as an injected gas for condensate reservoirs. There is evidence that phase behavior is nearly equivalent to methane injection, and costs may be somewhat lower.
These effects, however, are complex. Injected gas may sweep inefficiently between injection and production wells, causing poor economics. Because of the complexities of this process, cycling operations should not be undertaken without the aid of reservoir-simulation studies. Compositional reservoir-simulation models are available that can easily handle the thermodynamics and fluid-flow characteristics of a recycling project. Characterization of phase behavior is generally done through an EOS, which can be tuned to laboratory PVT tests.
Gas requirements in cycling operations
Miller and Lents expected to cycle the equivalent of approximately 115% of the gas in place to recover some 85% of the wet-gas reserves of the Cotton Valley Bodcaw reservoir. Brinkley indicated cycling-gas volumes of as much as 130% of original wet gas in place for various reservoirs. The requirements for a given reservoir will be driven mostly by economic considerations. The makeup gas needed for constant-pressure cycling is mainly the volume required to replace shrinkage by liquid recovery and the amount consumed for various fuel needs. For some composition, temperature, and pressure ranges, the removal of high-molecular-weight constituents from the produced wet gas may result in a higher compressibility factor for the injected dry gas; hence, the greater volume per mole injected may require little or no makeup gas for constant-pressure cycling.
The amount of gas not available for injection because of consumption for operating needs should be taken into account when determining makeup-gas requirements if pressure is to be maintained. The amount of fuel for compression and treatment plants depends mainly on the total amount of gas to be returned to the reservoir and the discharge pressure for the plant. Discharge pressure, in turn, depends on the total rate of injection demanded, the number of injection wells, and their intake capacities throughout the life of the operation. Other factors affecting the amount of gas required for overall operations are type of plant, type of liquid-recovery system used, and auxiliary field requirements (such as for drilling, completion, and well testing; camp fuel and power for maintenance shops, general service facilities, and employee housing; and other factors that vary from one case to another).
Moore reports that fuel consumption for the compression plant alone varies from 7 to 12 ft3/bhp-hr; this is probably for gases with heat values of approximately 1,000 Btu/scf.
If the fuel consumption is 8 ft 3/bhp-hr and the compression ratio is 15 (compressing from, say, 461 to 7,000 psia), fuel requirements would be 34.4 Mscf/MMscf injected. For an example reservoir originally containing 131 Bscf of wet gas, which might be cycled the equivalent of 1.25 times, the approximate compressor fuel consumption would be 5.6 Bscf, or approximately 3% of the gas handled through the plant.
Treatment-plant fuel and other plant needs added to compressor fuel bring the range of consumption inside the plant fence to 3 to 7% of the gas handled by a cycling plant. In addition to these needs and others mentioned earlier, possible gas losses that can occur in a cycling operation are: gas used in "blowing down" wells, should this be necessary for cleaning or treating purposes; small gas leaks at compressor plants and in field lines; and gas leaks resulting from imperfect seals or corrosion in well tubing, casing, and cement jobs. Remedial workover operations should be planned immediately when there is evidence of appreciable loss of gas between the compression plant and the reservoir sandface or between the outflow-well sandface and the plant intake.
- Miller, M.G. and Lents, M.R.: “Performance of Bodcaw Reservoir, Cotton Valley Field Cycling Project, New Methods of Predicting Gas-Condensate Reservoir Performance Under Cycling Operations Compared to Field Data,” Drill. & Prod. Prac., API (1946) 128–49.
- Brinkley, T.W.: “Calculation of Rate and Ultimate Recovery from Gas Condensate Reservoirs,” paper lO28-G presented at the 1958 SPE Petroleum Conference on Production and Reservoir Engineering, Tulsa, 20–21 March.
- Proc., Ninth Oil Recovery Conference Symposium on Natural Gas in Texas, College Station, Texas (1956).
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