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'.
Ali, Abdulla Ali Al (Al Dhafra Petroleum Operation Company, Complex C, ADNOC) | Park, Sangseok (Al Dhafra Petroleum Operation Company, Complex C, ADNOC) | Mukhtar, Muhammad (Al Dhafra Petroleum Operation Company, Complex C, ADNOC) | Ghorayeb, Kassem (Schlumberger Oil and Gas Services Company, American University of Beirut) | Alkhatib, Mohamad (Schlumberger Oil and Gas Services Company) | Ojha, Aditiya (Schlumberger Oil and Gas Services Company) | Shah, Abdur Rahman (Schlumberger Oil and Gas Services Company) | Ortiz, Jaime Moreno (Schlumberger Oil and Gas Services Company)
Early assessment of enhanced oil recovery (EOR) potential in fields that are at early development stages is becoming more common in the oil industry, ensuring that investment decisions are consistent with the EOR deployment once the field reaches maturity. Well, facilities and monitoring design maybe influenced to accommodate the EOR implementation, thus reducing Capex and mitigating project exposure. Challenges arise, as expected, due to the limited information, particularly when the field has not yet been under production and dynamic information of connectivity, compartmentalization and reservoir extend is scarce.
This paper describes the screening analysis performed on an onshore marginal green field in the UAE with four drilled wells and no production history with water injection considered on the approved development plan. The comprehensive screening workflow resulted on a narrow list of potential applicable EOR methods and their corresponding benefits allowing the operator to tailor development activities for early EOR de-risking and accelerated field deployment. A multi-dimensional approach was adopted using a combination of numerical, analytical methods and past EOR experience, to shortlist and rank the most attractive EOR development options, robustness of the selection (and ranking) was tested under the key reservoir uncertainties.
WAG was identified as one of the better suited EOR processes (complemented the planned waterflood) along with miscible CO2 injection (with possible WAG applications).
Alkhatib, Mohamad (Al Dhafra Petroleum Company) | Al Ali, Abdulla Ali (Al Dhafra Petroleum Company) | Mukhtar, Muhammad (Al Dhafra Petroleum Company) | Park, Sangseok (Al Dhafra Petroleum Company) | Ghorayeb, Kassem (American University of Beriut) | Nasiri, Amir (Schlumberger) | Shah, Abdur Rahman (Schlumberger) | Ojha, Aditya (Schlumberger)
A novel workflow was developed to select the optimal field development plan (FDP) accounting for the associated uncertainties in a green onshore oil field with a limited number of wells and no production data. The FDP was then revisited in view of the performance of wells drilled during the execution phase and updated as needed based on the acquired data .
Comprehensive uncertainty analysis was performed resulting in multiple subsurface realizations. A broad set of development scenarios and options were screened under uncertainty. The viable scenarios were then economically evaluated, resulting in an optimal FDP that is robust to uncertainty and the least risk prone from an economical point of view.
The used workflow was specifically suitable to test many development concepts and explore various options including horizontal well orientation, well pattern concept, pattern acreage and spacing, length of the horizontal sections, and landing of the horizontal sections.
Following an extensive techno-economic analysis of all possible combinations (900 in total), the most robust development concept was selected and analyzed considering the viable development strategies pertaining to plateau rate, drilling schedule, phasing, water injection timing and artificial lift timings.
A phased development approach was adopted enabling acquiring necessary data to mitigate the remaining uncertainty and avoid costly consequences of significant over- or under-capacity. Data acquired in one development phase were assessed and used to update the following planned phases, if necessary.
The study demonstrated that the field development could accommodate a delay in either water injection or artificial lift implementation. Although it was not recommended at this stage to delay either of them, it is noteworthy that the long lead time that may be incurred in the implementation of artificial lift or the risk of lower injectivity would not impact the field performance or ultimate recovery if contained to a few years during initial production. These results further reinforced the robustness of the proposed development plan.
Large subsurface uncertainty combined with an extensive set of possible development scenarios and options required cutting-edge uncertainty analysis and screening workflows to select the optimal FDP. These unique workflows can be readily used in similar green fields to help arrive at the final FDP.
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.
Unconventional reservoirs, due to their complexity, are among the greatest challenges to the oil and gas industry. After years of research, shale gas and tight gas reservoirs are now proven to be one of the unconventional reservoirs that are economically viable to fulfill the crucial energy requirements. Due to their low permeability and several other factors, they require advance techniques on both operational and simulation fronts.We performed several different simulations, both numerical and analytical, covering a variety of scenarios to compare shale gas and tight gas production forecasts. Both vertical and horizontal completions were analyzed. For horizontal completions, different hydraulic fracturing stage density was evaluated to identify the best possible production profile for a well and the entire field. The simulations show that Langmuir pressure, volume, rock density, well spacing, completion type, lateral length, and reservoir thickness have a large effect on production forecasts as well as simulations. The simulation results also show the effect of permeability in different cases. The aforementioned are key factors in development plan for a shale gas asset. All the values used for forecasting, both numerical and analytical, are typical for worldwide shales and belong to open source data. They have been selected carefully due to their close resemblance to unconventional reservoirs in Pakistan.