1. Calculate the density and molecular weight of the initial reservoir fluid. With this information, and knowing the initial reservoir volume (Vti), calculate the initial amount of gas in place (lbmols).
2. Using the reservoir fluid composition, distribute the initial moles of reservoir fluids into components, and store such quantities for material balance accounting.
3. Depletion step: Lower the reservoir pressure by a given amount (typically, 200 psi). Flash the reservoir fluid at the new pressure, calculate amount of moles in the gas and liquid phases (“GasT” and “LiqT”) and the densities and molecular weights of each of the phases at the new condition.
4. Expansion: With molecular weight, density, and total molar amount of each of the phases, calculate the new total volume that the fluids occupy at the new condition (Vexp).
5. Calculate the excess volume of fluids, taking the difference between the new volume upon expansion (Vexp) and the reservoir volume (Vti). This represents the volume of fluid that must have been withdrawn by the well in order to reach the newly imposed pressure condition
6. Calculate the percentage of liquid in the well stream using mobility ratio considerations. Trial and error procedure is necessary for the liquid accounting. The total amount of liquid available upon depletion (LiqT) must be distributed between the wellstream (LiqWS) and the liquid remaining in the reservoir (LiqR). Additionally, the moles of reservoir liquid “LiqR” can be expressed in terms of oil/condensate saturation. Oil saturations define the mobility of the gas and liquid phases.
7. Once LiqWS and (Vws)liq are known, obtain the total volume of gas withdrawn from the reservoir by subtracting the liquid volume (Vws)liq from the total wellstream volume (Vws). Express this gas volume in moles using reservoir gas density and molecular weight. Calculate the total number of moles of the wellstream.
8. Material Balance Accounting: Calculate the number of moles of each component remaining in the reservoir. To do this: subtract the number of moles leaving the well stream from the number in the reservoir before flashing for each of the components. Calculate the new overall composition of the reservoir fluid.
9. Calculate the overall composition of the produced well stream, by mixing the composition of gas and liquid coming along.
10. Surface Production Facility: Flash the incoming wellstream composition through the train of separations. Calculate the total amount of gas and liquid leaving the separation facility and GOR. Calculate the percentage of recovery from the reservoir.
11. A depletion loop has been completed. Go back to step 3 until abandonment pressure is reached (typically, 600 psia).
12. Plot liquid production, gas production, GOR, and recovery from the reservoir as a function of pressure depletion, from initial reservoir conditions to abandonment conditions.
Natural Gas Pipeline Modeling
- Once natural gas is produced and processed, few to several hundred kilometers may lie in between it and its final consumers.
- A cost-effective means of transport is essential to bridge the gap between the producer and consumer. In the technological area, one of the challenges pertains to the capacity of the industry to ensure continuous delivery of natural gas while its demand is steadily increasing.
- Thus, it is no wonder that pipelines have become the most popular means of transporting natural gas from the wellhead to processing — and from there to the final consumer — since it better guarantees continuous delivery and assures lower maintenance costs.
- Phase Behavior (P-V-T data) is crucial for all our engineering designs. Accurate prediction of the P-V-T properties of natural gases is especially critical when dealing with pipeline design, gas storage, and gas measurement.
- While describing natural gas pipeline design, it is necessary to distinguish between two cases
: the design of pipelines for transportation of regular dry gases (no liquid, single-phase transportation: Export gas pipelines)
: and the design of pipelines for transportation of wetter gases, where multiphase conditions due to condensate dropout may be possible. (Multiphase infield flowlines)
- The major variables that affect the design of gas pipelines are
: the projected volumes that will be transported,
: the required delivery pressure (subject to the requirements of the facilities at the consumer end),
: the estimated losses due to friction,
: the elevation changes imposed by the terrain topography.
- Overcoming such losses will likely require higher pressure than the one available when the gas is being produced. Thus, forcing a given gas rate to pass through a pipeline will inevitably require the use of compressor stations.
- Loss in mechanical energy results from moving fluids through pipelines. Energy losses in a pipeline can be tracked by trend of the pressure and temperature changes experienced by the flowing stream.
- Design equations relate pipeline pressure drop with the gas flow rate being transported. The following is the general equation for a single-phase gas pipeline flow in steady state:
- For near-ideal conditions, the effect of Z on flow rate is likely to be small. But for high-pressure flows, Z may deviate greatly from 1. Under these conditions, inaccuracy in the prediction of Z may lead to a substantial error in the calculated flow rate and thus a completely wrong pipeline sizing for design purposes
- Once a pipeline is deployed, it has a more or less a fixed operational region. An upper and lower set of operational conditions allowable within the pipeline (in terms of pressure and temperature) will exist.
- On the one hand, the upper allowable condition will be set by the pipe strength, pipe material, diameter, and thickness. These will determine the maximum pressure that the pipe can endure without failure (i.e., maximum operating pressure).
- On the other hand, maximum pressure and temperature of the compressor station discharge (which feeds the inlet of the pipe) will also contribute to set this upper level. It is clear that the conditions at the discharge of the compressor station cannot go beyond the maximum operating pressure of the pipe — otherwise the pipe will fail.
- The minimum or lower pressure and temperature condition of the operational region will be assigned by an agreement with the end consumer.
- The foregoing description of the operational region is shown schematically as the shaded area in this figure.
- In natural gas flow, pressure and temperature changes (P-T trace) may cause formation of a liquid phase owing to partial condensation of the gaseous medium.
- Retrograde phenomenon — typically found in multi-component hydrocarbon systems — takes place by allowing condensation of the gas phase and liquid appearance even under expansion of the flowing stream.
- The same phenomenon may also cause vaporization of the liquid phase such that it reenters the gas phase.
- Liquid and gas phase composition are continuously changing throughout the pipe due to the continuing mass transfer between the phases.
- In general, the amount of heavies in the stream determines the extent of the retrograde behavior and liquid appearance. Previous figure shows a P-T trace or operational curve for a given pipeline, which is always found within the pipeline operational region.
- This figure also shows four typical phase envelopes for natural gases, which differ in the extent of their heavy components.
- For a given composition, the prevailing pressure and temperature conditions will determine if the fluid state is all liquid (single-phase), all gas (single-phase) or gas-liquid (two-phase).
- Each envelope represents a thermodynamic boundary separating the two-phase conditions (inside the envelope) from the single-phase region (outside).
- Each envelope is made of two curves: the dew point curve (right arm, where the transition from two-phase to single-gas occurs) and the bubble point curve (left arm, where the transition from single-liquid to two-phase occurs). Both arms meet at the critical point.
- The wetness of the gas is an important concept that helps to explain the different features in the figure.
- This concept pertains to the amount of heavy hydrocarbons (high molecular weight) that are present in the gas composition.
- In the figure the driest gas — i.e., the least wet — can be recognized as that whose left and right arms are the closest to each other, having the smallest two-phase region (gas A).
- In this figure, it can be seen that the right arm is extremely susceptible to the presence of heavies in the natural gas composition. Depending on the gas composition, the pipeline operational region can be either completely free of liquid (gas A, the driest) or partially submerged in the two-phase region (gas B, C). If the gas is wet enough, the pipeline will be entirely subjected to two-phase conditions (gas D, the wettest).
- In the figure, a pipeline handling a dry gas (gas A) will be operating a single-phase mode from its inlet through its outlet. For this case, any of the popular single-phase gas equations (Weymouth, Panhandle type, AGA equation) can be used for design purposes and to help to predict the actual operational curve (P-T trace).
- If a richer gas comes into the system (gas C), it will show a single-phase condition at the inlet, but after a certain distance the pressure and temperature conditions will be within the two-phase region.
- The case might also be that the system is transporting a wetter gas (gas D), in which case it would encounter two-phase conditions both at the inlet and at the outlet of the pipe.