Hassi R'Mel Field is one of the biggest gas-condensate fields in the world. The southern area of this field, Module 02, has been depleted by vertical wells since 1979. Since 1981, water production has exceeded the allowed water limit. The salinity of the produced water is about 05 g/l, which is the maximum salinity allowed at the surface facilities. As a result, severe reservoir damage may have occurred. So the producing reservoir levels (C) were shut-in. The primary objective of this study is to investigate the performance of horizontal wells in a Sector-Model, to predict their behavior versus water production, and condensate recovery. To simulate the depletion processes, a compositional simulation is conducted to investigate the following phenomena in the case of horizontal and vertical wells:Water influx effects,Comparison of horizontal well drawdown pressure to that of vertical wells, andThe influence of the horizontal well length section and reservoir thickness on horizontal well productivity, and condensate recovery. A reservoir characterization is made, and a 3-Parameter Peng-Robinson equation of state (3-PR-EOS) is established to characterize the reservoir fluids. A 3-D Cartesian Sector Model was built for the zone of interest in order to predict the performance of horizontal wells and the different phenomena that can be present in retrograde gas-condensate reservoirs, and to analyze the most relevant reservoir parameters that affect horizontal wells performance. The obtained results showed that the use of horizontal wells is a proven technology for reducing water influx problems and improving condensate recovery. The condensate production of a horizontal well compared with that of a conventional vertical well can be increased by a factor of 1.30, owing to less condensate accumulation in the region of the producing well. Introduction Gas condensate reservoirs differ essentially in their behavior from conventional gas reservoirs, and the optimization of hydrocarbon recovery needs careful reservoir analysis, planning, and management. At the time of discovery, gas condensates are often found as a single-phase gas in the reservoir. However, as the production is carried out, there is an isothermal pressure decline and as the bottomhole pressure in a flowing well falls below the dew-point of the fluid, a liquid hydrocarbon phase is formed. Due to lower permeability to liquid and a high liquid-to-gas viscosity ratio, most of the condensed liquid in the reservoir is unrecoverable and constitutes the "condensate loss". Condensate loss is one of the greatest economical concerns since the condensate contains valuable intermediate and heavier components of the original fluid now trapped in the reservoir. The liquid keeps accumulating until the critical liquid saturation is reached. Once this liquid starts flowing, the flow of gas and liquid is subjected to the law of multiphase flow in porous media. For single-phase reservoirs, whether oil reservoirs or gas reservoirs, it has been well established in the literature that horizontal wells present significant advantages over vertical wells. Higher gas rate and increased liquid recovery are the main advantages that horizontal wells can offer. In horizontal wells, drawdown pressure is three to four times lower than vertical wells for the same flow rate. Therefore, there is less condensate deposited near the horizontal wellbore. This affects favorably the productivity of a gas condensate reservoir, as less blockage will occur in the skin zone. Literature review Gas condensate-related topics, such as well deliverability, well testing interpretation, gas-condensate inflow performance, and flow in reservoir in general, have been long-standing problems. From the literature, many studies have been conducted to predict the production behavior of a well in gas condensate reservoirs.

A new field in offshore Abu Dhabi is currently being developed by ADMA-OPCO by combining the production from six distinct carbonate reservoirs, each of which has different characteristics. The production and injection streams from all the reservoirs will be mixed and processed using common surface facilities (Offshore Super Complex).The development scheme was optimized based on the integration of the available geological, seismic, petrophysical, and dynamic reservoir data into six separate reservoir models. The optimized development plan was defined for each reservoir using its corresponding individual simulation model, where all reservoir models are compositional with similar pseudo-components.Because the field will be developed as a gas self-sufficient field with no gas export line, all the produced gas from the six reservoirs has to be managed within the field. After removing the fuel gas, part of the total produced gas is used for gas lift; whereas, the remaining gas is compressed and re-injected into reservoirs D, F, and G to ensure full gas balance.The facilities are shared by all reservoirs, so to further enhance field-development optimization modeling, especially with gas-recycling requirements, an integrated, multi-reservoir model with surface network was constructed. In this model, the six reservoirs were fully coupled with a single surface network, including wellhead towers, production/injection pipelines, and the Super Complex layout. This was accomplished by using a next-generation simulator that allows both surface and subsurface equations to be solved simultaneously.This paper addresses the steps followed and the challenges encountered and then summarizes the main outcomes. In addition, it provides a comparison with the results obtained from the single-reservoir models when run individually.The results obtained from the integrated model were slightly different when compared to those of the individual models because of the newly developed surface EOS model and the impact of the network on the individual reservoir's performance. The integrated reservoir model (IRM) proved its advantages, especially for gas recycling, by eliminating the previous iterative runs performed to achieve the field gas balance and by its ability to make the most effective usage of both water and gas plans to maximize recovery.

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Авторское право 2006 г., Общество инженеров-нефтяников Этот доклад был приготавливан предьявления в 2006 Российской нефтьегазовой технической конференции и выставке состоится в Москве 3-6 октабря 2006.Данный доклад был выбран для проведения презентации Программным комитетом SPE по результатам экспертизы информации, содержащейся в представленном авторами резюме. Экспертиза содержания доклада Обществом инженеров-нефтяников не выполнялась, и доклад подлежит внесению исправлений и корректировок авторами. Материал в том виде, в котором он представлен, не обязательно отражает точку зрения Общества инженеров-нефтяников, его должностных лиц или участников. Доклады, представленные на конференциях SPE, подлежат экспертизе со стороны Редакционных Комитетов Общества инженеров-нефтяников. Электронное копирование, распространение или хранение любой части данного доклада в коммерческих целях без предварительного письменного согласия Общества инженеров-нефтяников запрещается. Разрешение на воспроизведение в печатном виде распространяется только на резюме длиной не более 300 слов; при этом копировать иллюстрации не разрешается. Резюме должно содержать явно выраженную ссылку на то, где и кем был представлен данный доклад. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836 U.S.A., факс 01-972-952-9435..

Traditionally, geoscientists, drilling, reservoir, and facility engineers work separately on projects. The workflows between these disciplines are typically onerous, iterative, and time consuming because there is no common environment between roles. For offshore fields, the limited number of towers from which wells can be drilled make well planning a critical process for a successful development. Usually, planning is done on a well-by-well basis, which could introduce the potential for increased risks. ADMA-OPCO has begun developing an offshore green field through drilling about 90 wells (duals and singles) from eight wellhead towers. The development scheme for this field is optimized per reservoir, five-spot water injection, natural depletion, and gas injection. For each tower, slots (injector vs. producers) and allocations have to be defined with high confidence and be communicated to surface project teams to start the design and engineering process. This exercise requires working all well trajectories (drillable wells that meet the statements of requirements). Early in the field-development process, the common practice is to do the well-profile work on a well-by-well basis, which takes a minimum of three to five days per well depending on well type and complexity. This paper addresses a different approach that is used by ADMA-OPCO, which allowed for accelerating the planning process by integrating all stakeholders for the objective of reducing the working hours while optimizing the trajectories and taking into account all criteria and safety guidelines executed within a 3-D static-model environment. As an outcome, more than 100 horizontal drains were successfully optimized, and slot allocations were defined for all towers within 20 working days (minimum of 380 days would be required if done on a well-by-well basis). A drilling footage of more than 20, 000 ft was saved after optimization. Additionally, the real collaborative value was seen in the integrated working sessions, resulting in an improved deliverable.