Ali, Hamza (Schlumberger) | Shah, Abdur Rahman (Schlumberger) | Akram, Agha Hassan (Schlumberger) | Khan, Waqar Ali (Schlumberger) | Siddiqui, Fareed Iqbal (Pakistan Petroleum Limited) | Waheed, Abdul (Pakistan Petroleum Limited) | Ahmed, Faizan (Pakistan Petroleum Limited)
A recent study addressed the modelling challenges of Alpha* gas condensate field. Alpha gas condensate field has a gas in-place of about 1 TCF, and both condensate and black oil production in addition. The field has been producing from two reservoirs SI and DI, for the past 26 years. Alpha field is subdivided into two segments called the Central Area and the Northern Area which are separated by a fault as shown in Figure 2. * Not its real name. One of the most unusual features of Alpha field are the'phase switch wells'.
In the wellbore, phase segregation and density changes become significant during gauge pressure measurements. Static pressure surveys capture this change in density, provided the gauge is stationed at different depths in the lower part of the tubing, where this change is most expected. These static pressures are then corrected to datum depth to determine the depletion across the field. Conventionally, a one step pressure correction is used to correct the pressures from the gauge station to datum depth using the wellbore pressure gradient. This approach assumes that the same gradient exists, both in the reservoir and in the wellbore, which is generally not true in the case of gas condensate reservoirs, as well as oil & water producers. This paper presents a two-step pressure correction workflow for gas condensate reservoirs.It proposes to establish a gradient from pressure measurements acquired from lower gauge stations, as segregated fluid density changes even in the liquid column. This is the wellbore gradient. It makes use of PVT parameters to determine the gradient developed by the reservoir fluid, which is independent of the wellbore gradient, to ensure that the correction to datum depth incorporates the actual reservoir conditions.
The subject Gas Field is located in the Sulaiman Fold Belt (SFB) in Pakistan. A realistic 3D static model was constructed for the challenging multiple reservoirs in the Field which included both clastics and carbonates. Four main reservoir horizons were modeled.
The steps involved in the Reservoir engineering analyses were: analyze PVT, well test, Static Pressure Data, and Core. The static pressure analysis helped define hydraulic compartmentalization in the field.
WHFP measurements were not available in the desired accuracy and density. A surface network model was used with plant inlet pressure as the primary constraint in order to obtain the required information. Satellite based elevation information was used to establish an accurate model with respect to pressure drop due to liquid hold up in pipelines.
The History Match in the field was performed on a Zone by Zone basis. In the absence of a 3D seismic cube, many of the faults in the field could not be interpreted, yet their presence was predicted by a closely matching Sand Box Model. This was an important clue which led to a useful approach regarding the location of simulation faults distributed in the entire field. An innovative approach was used in order to calibrate the size of sand lenses in one of the zones.
The final step was the forecasting and development of Optimal Scenario using Economic analysis. Many scenarios were tested, and the optimal scenario was identified. Maximum use was made of existing wellbores through re-completion, and new drilling was minimized. Furthermore, the impact of increasing the currently low Gas Price was tested. It was concluded that doubling of the gas price of the field would increase the NPV 3 times delay abandonment by 6 years.
The Gas Field is located in the Sulaiman Fold Belt (SFB). Eighteen (18) wells in all, those have been drilled in the Field. Currently 12 wells are producing Gas. The primary target horizons in Field are the Sui Main Limestone (SML) and Lower Ranikot (LRKT). However, the Dunghun Limestone and Pab Sandstone are also producing in some of the wells. The depositional sequence consists of clastic and carbonate succession. The stratigraphy of the reservoirs is strongly influenced by the structural evolution of the Sulaiman Fold Belt and initial rifting of the Indian Plate.
In many oil wells, production is commingled from several layers. In such environments, understanding the properties of individual layers is essential to reservoir surveillance and production optimization. The inflow properties that typically require measuring are productivity index (PI), water cut, and static reservoir pressure. These measurements have traditionally been taken with wireline-conveyed production logging tools (PLT); however, in many wells and operating environments, completion and logistic considerations make running these tools difficult or even impossible. In those instances, an alternative is required. This paper presents a new procedure based on multirate testing in combination with distributed temperature sensors (DTS), an electric submersible pump (ESP) fitted with a gauge in the commingled fluid stream, and conventional surface testing. The additional test rates provide sufficient equations to resolve all the unknowns, whereas the DTS provides essential information such as which layers are producing and which are taking fluid, as well as a mass flowrate tool for measuring the flow rate of each layer. The procedure requires varying well flow rates over a range sufficient to ensure that all layers are producing, which in many cases requires an ESP to provide sufficient drawdown to overcome crossflow as well as a variable-speed drive to establish the test rates. The theoretical basis for the protocol is described, and an example is detailed to demonstrate the validity and robustness of the method for determining inflow properties. Finally, theoretical and practical guidelines are provided to demonstrate how the test procedure is affected by fiber-optic resolution, fluid properties, and the geothermal gradient. For wells equipped with forms of artificial lift such as ESPs, beam pumps, and progressive cavity pumps (PCPs), running PLTs is often not possible because of the completion obstruction. In such cases, this new DTS-enabled procedure has the potential of becoming the PLT substitute of the future.
A Paleocene dolomite in northeastern Libya was modeled using three porosity types: matrix porosity (intercrystalline plus the separate vugs), horizontal-to-subhorizontal solution-enlarged vuggy porosity generated by dissolution and named "touching vugs,?? and fracture porosity.
The touching vugs, which acted like fractures in their dynamic behavior, are modeled as a very permeable discrete fracture network (DFN) in PETREL* seismic-to-simulation software. Their presence is known primarily due to pressure buildup analysis, and it is expected that they would be interconnected over hundreds of meters.
The primary challenge in dual-media modeling is being able to characterize and predict the dynamic behavior of the complex matrix + fracture + touching vug system. There are three wells in this area of northeastern Libya with pressure buildups that have an unusually distinct and pronounced dual-porosity signature. Each well has been matched by adjusting the five primary parameters: matrix and fracture porosity and permeability, and the sigma shape factor. Aquifer strength also had to be adjusted.
There are some aspects of the dynamic behavior of this reservoir that are of particular interest:
This paper presents the dynamic features of the reservoir and demonstrates how the simulation model was calibrated using all available information, in particular, the pressure buildups.
A study was carried out to forecast the productivity of a hydraulically fractured well in a retrograde gas-condensate sandstone reservoir using a numerical model. The fracture was explicitly modeled as a set of high-conductivity cells.
At the gas velocities normally encountered in hydraulic fracture proppant packs, non-Darcy pressure drops dominate, and the apparent proppant permeability is one or two orders of magnitude lower than the Darcy permeability measured at single phase low-rate conditions. This is particularly true if a liquid phase is also flowing. The apparent permeability of the proppant is a function of:
Gas velocity (hence: rate and flowing pressure)
Ratio of free liquid rate to gas rate
Stress on the proppant
Type of proppant
Thus, apparent proppant permeability will vary with distance from the wellbore, increasing towards the tip of the fracture where liquid ratio and velocity are lower.
This variation of permeability was explicitly modeled in the proppant pack by dividing it into segments and calculating the permeability in each segment. As a result of this modeling, the impact of increased fracture length on productivity was found to be more significant than in simpler modeling where one permeability value is used for the entire proppant pack.
The variation of apparent proppant permeability along the length of the fracture and its impact on well productivity are discussed in this paper. A comparison of predicted well productivity is also made with the use of a constant permeability value for the proppant in numerical and analytic simulators. We will show that using a constant proppant permeability value results in an estimate of optimal fracture length that is too short.
An innovation in the methodology of conducting drillstem tests (DSTs) in tight gas reservoirs is presented, along with a simplification in the interpretation of the data obtained. DSTs in tight gas reservoirs are a problem because the flow rates are often too low to be measured by conventional equipment. In these cases a normal flowing and buildup test should be followed by a closed chamber test to produce usable estimates of flow rates at various times during the preceding normal flowing and buildup test. This estimated flow rate can then be used to interpret the buildup after the flow testing, which is produced by shutting the downhole valve.