Integrated Field Development Plans of Akkas Gas Field

Akkas gas field is the biggest natural gas field in Iraq that is located in the western desert area. The field contains around (9 BSCF) of approved gas reserve from the conventional rock source. This paper presents field development planning process combined with economic analysis comprises, the number of wells that yields in maximum net present value (NPV), the recovery factor and raw gas production rates for the total number of suggested wells that have been estimated, as well as the cumulative gas produced with time. The development plans were elaborated concerning different types of well geometries and operational constraints. Full comparison analysis for all presented plans regarding NPV, recovery factor, discounted cash flow versus production time, forecasted production rate, as well as forecasted cumulative production with time have been presented. Sensitivity analysis has been made to determine well and reservoir controlling parameters that leads for best operating field development plans. The study shows the effectiveness of horizontal well type compared with vertical wells; as well as, the effect of reservoir permeability on field development plans, the results show that the field could be operated at target plateau rates of (250, 500 and 750 MMSCF/D). It also shows the superior effect of stimulation processes in increasing the NPV and field recovery factor using less number of wells


1-Introduction:
Akkas gas field is the biggest dry gas field in Iraq, which is located in the western desert area (Al-Anbar) province. The field contains about (9 BSCF) [1] of approved gas reserve from the conventional rock source (Khabour) formation. Moreover, a recent study prevailed that the Silurian hot shale, which is one of the field's formations, may also contains about (4.55 BSCF) of recoverable gas [2]. This field has not been developed because of the country's traditional focus on oil reservoir during the past; but currently, Iraqi authority has paid great attention to utilize this high clean energy for both domestic requirements and support the world demands.
No.28-(9) 2020 Journal of Petroleum Research & Studies (JPRS) E104 Field development planning comprises a great amount of investments and involves a high number of parameters related to the geological and structural characteristics of the reservoir, to the operational scheduling and the economic scenario. The importance of this study that can help in the management decision making process, leading to better recovery strategies that increase both reserves and profitability of reservoirs.
The use of reservoir simulation is very important to provide reliable production forecast and correct predictions for field recovery potential. During the initial field development phase the amount of available information for the reservoir is very restricted and it is very difficult to obtain a correct reservoir model. Therefore, the use of analytical simulation models provides more appropriate and lead to better results. In this study, advance software technology IHS-Fekete "Evolution" software [3] has been used, the software has full capability to verify different scope plans, forecast different types of well geometry including vertical, inclined, horizontal, hydraulically fractured as well as any combination of these types; moreover, the software has the capability to evaluate the performance of hydraulically fractured gas wells.
This work present technical and economical field development plans, including a robust optimization procedure that uses the production forecasts generated by reservoir optimization for the evaluation of an objective-function (NPV). This methodology helps in the decision making process granting a correct evaluation of relevant parameters in field recovery planning and it provides adequate solutions for any number of runs.

1.1-Field description:
The reservoir is an anticline dome extended along North Western-South Eastern of dimensions (L50*W18) Km at the Northern of Khabour formation which considered the main natural productive zone [1].
The reports of MoO [1] divided this structure into seven sub-layers based on rock types and shale content. The main layers of Akkas field are the (upper Khabour) and (Lower Khabour), which consist of sandstone rocks and contains the biggest quantities of natural gas reserve of this field. The net pay thickness of upper Khabour (129 ft) and for lower Khabour (140 ft), the measured porosity (7.6 % and 9.7 %) for upper and lower Khabour No.28-(9) 2020 Journal of Petroleum Research & Studies (JPRS) E105 respectively. While, the average water saturation of upper Khabour (52.5 %) and for lower Khabour (35.6 %).
The report prevailed that the average core permeability around (0.07-1.2 md) for upper and lower Khabour respectively, while the well test analysis shows that the permeability range (3 to 80 md) for vertical and horizontal directions respectively. While, the initial reservoir pressure is 3800 psi, and temperature of 220 F at datum of 2120 m. The shale volume range between (0 -40%).

2-The stages of development plans:
Three main stages have been implemented in executing successful gas field development plans, which involves (A-Scoping, B-Forecasts and C-Comparison), the following description may give a useful knowledge of each stage: A-Scoping: is one of the procedures that help make the development program so powerful. Scoping is used to input all required reservoir and economic data and run a large number of scenarios quickly and efficiently. Scoping is a starting point to evaluate a whole range of scenarios for economically developing a gas field. It gives answers to questions that may raise for "1-How many wells are needed to develop a field, 2-What is the effect of permeability, 3-What type of well or completion -vertical, hydraulic fracture, horizontal, 4-When the wells come on stream, 5-When does drilling another well becomes uneconomic and 6-Project life" [3] B-Forecasts: is where the engineers' takes the knowledge learned from running various scoping analyses and applies a more in depth study to the most likely and/or most productive scoping scenarios. The Forecasts allow the engineers to manipulate particular parameters for each individual well placement, well production start time, and well type to help achieve a further assessment and devise a direction for a future development strategy [3].
C-Comparison: this section allows seeing all scopes and forecasts currently created in one plot for quick and easy better decision.
No.28-(9) 2020 Journal of Petroleum Research & Studies (JPRS) E106 The advantages of the presented field's development plans are to establish the (1-the number of wells to be drilled to reach production objectives; 2-the recovery techniques to be used to extract the fluids within the reservoir; 3-the starting time of wells to come on stream; 4-the best location of drilled wells; 5-the reasonable maximum field gas rate; 6the break number of wells becomes uneconomic; 7-the effects of horizontal on gas production; 8-comparing the effectiveness of vertical wells and horizontal wells; 9-the effect of the horizontal wells length on production; 10-the effect of uncertainties of permeability or net pay on production and 11-the economics of particular development scenarios).

2.2-Reservoir parameters and Economic sensitivity analysis
Implementation sensitivity analyses on parameters such as, the permeability, net pay, skin, surface gas loss, the maximum gas rate, as well as using economics such as gas price, well/facilities costs, drilling cost, and royalties in determining the optimum production scenarios.
The economic sensitivity analysis is very important for a recovery strategy planning, the parameters like gas price that is strongly influenced by technical and political circumstances tend to show significant variations throughout the project life [4]. The use of the advance software tools allows an accurate evaluation of the potential of each alternative comprised in the set of recovery patterns presented by the methodology regarding different feasible economic scenarios, and the objective at this stage of the methodology is to identify the alternatives that present low financial risk and that are less influenced by economic scenario alterations.
In this study, the reservoir data mentioned in field description section, as well as the

3-Work development Plans:
Based on the parameters mentioned in reservoir description section, the material balance calculation of gas recoverable reserves for Akkas field have been estimated around (2.832 BSCF) and (5.191 BSCF) for upper and lower Al-Khabour formations respectively. The total estimate is very close to that announced by both MoO [1] and other technical reports [2].
Line spot pattern has been used in distribution wells location either vertical open hole or horizontal wells, with an equal lateral section length from (500 -3000 ft) parallel to reservoir length. The vertical wells have been assumed penetrating the entire Khabour formation, with the perforations have been taken place within the upper and lower Khabour intervals only. While, the horizontal wells are assumed penetrating the two intervals using bilateral horizontal sections.
The study assumed no gas condensate may occur during production; moreover, no production comes from the hot shale (Sullirian) zone, which needs special technology to produce the absorbed gas.
The uncertainty in reservoir permeability values between measured cores and well test analysis has been taken into consideration with the sensitivity analysis.
In particular, because the break-point for the gas field development is generally low compared to oil fields [4], as well as the development planning comprises a great amount of investments [5]; therefore, the development plans need to be established taking longterm stable recovery into consideration. Thus, the running flow duration for Akkas field development has been taken 20 years that allows in evaluating the feasibility of the suggested development plans.

Note, due to very big number of the graphical results for Scope, Forecast and
Comparison runs and the big number of scenarios that take the effect of bottom hole operating pressures, stimulation effect, production pipe diameter, as well as the economic variation; we have presented only some of selected plots for the suggested cases, which No.28-(9) 2020 Journal of Petroleum Research & Studies (JPRS) E108 may show the wide analysis achieved by the study. However, all details of scopes, forecasts and comparison can be submitted to Ministry of oil soonest requested.
Several field development plans have been suggested based on the target plateau rates of (250, 500 and 750) MMSCF/D for period of (20) years, which allows in determining the taken into consideration reservoir and wells operating pressure; as well as the uncertainty of reservoir permeability. Moreover, the economic parameters such as well drilling cost, operating cost, gas price, compression cost and working efficiency. These plans could be demonstrated as follows. All Scopes for all presented scenarios have been runs using (40) vertical or horizontal wells, this allows in determining the real numbers of vertical or horizontal wells may require in the forecast stages.
Secnario-1; Plateau rate (250) MMSCF/D; operating bottom hole pressure (3150) psia, skin factor taken from well test analysis (15). This scenario shows the sensitivity of permeability variation between measured core values and that obtained from well test analysis on recovery factor and production rate; therefore the permeability sensitivity of (3, 10, 40 and 80 md) have been considered in this scenario, as shown in Figs. (1-8) that can be illustrated as follows; Scope -1; the plateau could be sustained the plateau of (250) MMSCF/D for a period of (3) years, and then undergoes a decline rate about (1.25) MMSCF/D/Month for about (10) years, then declines by (1.8) MMSCF/D/Month for (5) years, at which the field reaches its abandonment production rate.
Scope -2; the plateau could be sustained the plateau of (250) MMSCF/D for a period of  (2) years.
Scope -3; the plateau could be sustained the plateau of (250) MMSCF/D for a period of (13) years, and then undergoes sharp decline rate about (16.7) MMSCF/D/Month for the last (1) year, at which the field reaches its abandonment production rate.
No.28-(9) 2020 Journal of Petroleum Research & Studies (JPRS) E109 Scope -4; the plateau could be sustained the plateau of (250) MMSCF/D for a period of (13.5) years, and then undergoes very sharp decline rate about (250) MMSCF/D/Month for the last (1) year, at which the field reaches its abandonment production rate.
Scope -1H; the plateau could be sustained the plateau of (250) MMSCF/D for a period of (6) years by the first eight wells put them in production, and then could be sustained the plateau of (210) MMSCF/D for a period of (8) years by another twelve wells added them in production. Then the field undergoes a decline rate about (2.85) MMSCF/D/Month for about (6) years, to reaches its final rate of (10) MMSCF/D at the end of forecasted period of (20) years.        (15). This scenario shows the sensitivity of permeability variation between measured core values and that is obtained from well test analysis on recovery factor and production rate; therefore the permeability sensitivity of (3,       Cumulative production MMMSCF 1100 1220 1250 1250 1200

Net Present Value versus Total Number of Wells
Secnario-3; this scenario is built same as scenario (2)      can be obtained using horizontal wells of (2000) and (4000) ft of Scopes 1H and 2H respectively.

Conclusions:
The following conclusions could be extracted from the study and can be summarizing as follows; 1-The reservoir has great potential of gas reserve both free gas and shale gas.
2-The recovery factor obtained by natural gas flowing around (15 %).
3-The maximum number of wells that yields maximum RF and NPV could be less than 30 wells.

4-
The superiority of well stimulation in increasing the NPV throughout increasing the field recovery factor using less number of wells.