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Mohamed Latif, Mohd Anwar (ADNOC Onshore) | Bedewi, Mahmoud (Halliburton) | Abdulayev, Azer (Halliburton) | Al Saadi, Noura (ADNOC Onshore) | Mohammed Saleem, Babar (ADNOC Onshore) | Al Bairaq, Ahmed Mohamed (ADNOC Onshore) | Al Ameri, Ammar Faqqas (ADNOC Onshore)
A giant gas field consisting of six stacked carbonate reservoirs of Lower Cretaceous age with gas caps and non-associated gas where the production follows a depletion scheme is discussed. The field has a production history of more than 30 years with more than 150 gas condensate wells flowing to a common surface network, which means production decline is inevitable.
This study assesses various mitigation actions to extend the plateau or minimize the anticipated inevitable production decline, and optimize costs while adhering to a service level agreement (SLA) with the consumer gas plant.
This paper illustrates how the use of an integrated asset model (IAM) as a digital twin of the actual asset can help provide a holistic approach for evaluating critical investment decisions.
The proposed mitigation actions were mainly focused on surface facilities because gas fields are sensitive to backpressure; the mitigation actions were primarily geared toward reducing backpressure to remedy the anticipated production decline.
Gas plant inlet/outlet pressure reduction proved to provide significant plateau extension. This finding was verified by means of field trials. Intermittent and weak producers responded positively to the implementation of wellhead compression during the IAM simulation; consequently, a pilot was implemented in the field to verify the simulation conclusion. IAM also proved that adding 20 new infill wells would help accelerate gas production, if necessary; but, it requires further economic justification before implementation.
Simulating scenarios, such as the segregation of wells currently sharing flowlines, had a minor effect to overall field production. A previous reconfiguration of compressors within the compression stations proved beneficial in mitigating production decline and accelerating gas volume. However, because of operational risks and associated costs, future reconfigurations showed minimum impact.
A significant portion of the study was focused on modeling the downtime of various components of the asset surface facilities as per the integrated shutdown plan (ISDP) and identifying alternative routes to minimize overall gas production disruption and to adhere to the SLA commitment.
The focus on precisely simulating the operational side of the field was enabled by the use of IAM as a digital twin of the actual asset. In addition to the usual simulation benefits, such as the assessment of various sensitivities before implementing significant investments in real life, this holistic approach can help realize cost-saving opportunities and help ensure future adherence to the contracted gas rate.
An integrated asset modeling (IAM) approach was used to evaluate a reinvigorated facilities configuration for a mature giant oilfield offshore Abu Dhabi. The field has produced for 50 years through steel jacket-based "supercomplex" facilities. A new artificial islands-based strategy has been envisioned to cater to higher production requirements, replace ageing facilities approaching their design lives, and debottleneck the water and gas handling capacity.
Commercially available reservoir simulation software was used to develop the integrated reservoir simulation model. The IAM fully couples three compositional simulation models for each reservoir unit to an extensive pipeline network and incorporates the timely rerouting of existing facilities to the new processing centers. Eventually, the "supercomplexes" only receive wellstream fluids from the existing wellhead towers (WHTs) network and redirect production to the new centralized processing island where it goes through a three-phase separation. Recent pressures and production data were used to calibrate the IAM.
The IAM was successfully used to evaluate the impact of the new surface layout on production. The production profiles from the standalone models, based on constant terminal node pressure at the wellheads, were compared to the IAM profiles. Pragmatic guidelines were defined to obtain representative profiles from the standalone models. Additionally, the IAM was used to guide the future facilities design by addressing the sizing of the water and gas handling capacity and identifying future surface bottlenecks. Moreover, the compositional IAM allowed quantifying the H2S content in the stream. The reservoirs being drained have varying levels of H2S, and prediction of the gas sourness is an important parameter for separator and pipeline design and for determining the sale gas value. Finally, the IAM had flow assurance applications, such as assessing the changes in pipeline temperature. Indeed, as the field matures, wells are forecasted to produce more water, raising the field water cut from the current 7% to 20% in the next 10 years. This increase in water cut would increase the pipeline temperature. The IAM allowed forecasting of the steady-state pipeline temperature to ensure existing pipelines are operated within specifications and to help design future flowlines.
Patacchini, Leonardo (Abu Dhabi Marine Operating Company) | Mohmed, Farzeen (Abu Dhabi Marine Operating Company) | Lavenu, Arthur P. C. (Abu Dhabi Marine Operating Company) | Ouzzane, Djamel (Abu Dhabi Marine Operating Company) | Hinkley, Richard (Halliburton) | Crockett, Steven (Halliburton) | Bedewi, Mahmoud (Halliburton)
The classic method for initializing reservoir simulation models in the presence of a transition zone, based on primary drainage capillary-gravity equilibrium, is extended to account for partial reimbibition post oil migration. This tackles situations where structural events, such as trap tilting or caprock leakage, caused the current free-water level (FWL) to rise above deeper paleo-contacts. A preliminary primary drainage initialization is performed with zero capillary pressure at the paleo (or deepest historical) FWL, to obtain a minimum historical water saturation distribution. From a capillary pressure hysteresis model, it is then possible to determine the appropriate imbibition scanning curve for each gridblock, which are used to perform a second initialization with zero capillary pressure at the current FWL. With the proposed method, log-derived saturation profiles can be honored using a physically meaningful capillary pressure model. Furthermore, when relative permeability hysteresis is active, it is possible as a byproduct of the initialization to assign the correct scanning curves at time zero to each gridblock, which ensures that initial phase mobilities (hence reservoir productivity) and residual oil saturation (hence recoverable oil to waterflood) are modeled correctly. This is demonstrated with a synthetic vertical 1D model. The method was implemented in a commercial reservoir simulator to support modeling work for a giant undeveloped carbonate reservoir, where available data suggest that more than 3/4 of the initial oil in place could be located between the current FWL and a dome-shaped paleo-FWL. This work is used as a case study to illustrate the elegance of the proposed method in the presence of multiple (or tilted) paleo-FWLs, as only one set of capillary pressure curves per dynamic rock-type is required to honor the complex logderived saturation distribution.
The building, calibration and validation of a coupled simulation model treating two giant subfields simultaneously with their common water injection facilities are presented. The primary objectives of the project were to develop a tool providing more accurate forecasts by consistently allocating injected volumes to both subfields, and to help identify network upgrades necessary to accommodate the long-term development plan. Simulation results presented in this paper are nevertheless based on an eight-years (2015-2023) drilling schedule, followed by no further activity.
Building of the model involved migration of separate reservoir and network models to a next generation simulator capable of treating both surface and subsurface flows fully implicitly. Coupled model operation without network (i.e., with wells constrained by guide-rates considering a common field injection target) and with network (i.e., with wells constrained by self-consistently calculated backpressures) are discussed and compared in detail. For the latter case, particular care is necessary in terms of modeling injection modules.
Calibration consisted of shifting the lift performance curves of more than 200 active injection strings, in order to make up for any mismatch in the flowing wellhead pressure and help ensure rate continuity at the transition from history to forecast. Tuning of the surface network, modeled "as is" according to its physical layout, was not necessary based on the good backpressure match obtained for the more than 40 active injection towers.
Validation was performed through a one-year blind test, from April 2015 (start of forecasts) to March 2016. The procedure first involved well-by-well comparison of injection rates, for which, because of allocation uncertainties, a qualitative match was accepted; it second involved a comparison of the injection split between the two subfields, for which less than a 1% mismatch was achieved.
In conventional modeling, the flow from the reservoir to the wellbore is decoupled from the flow in the surface pipelines and the facilities. This approach is sufficient during history matching; however, it is less accurate for future performance predictions where precise hydraulic calculation is necessary to assess the pipelines and facilities design. This paper studied an offshore green field where production from six different reservoirs in which several single and multilateral horizontal wells are drilled and connected to offshore wellhead towers being connected by pipelines to an infield super complex. Because surface facilities are shared by all reservoirs and the field is being developed as a gas self-sufficient field wherein the processed gas from the first stage of separation, after removing the fuel, must be re-injected, it has been recognized that conventional modeling is not appropriate for defining the long-term development plans (LTDP) in addition to identifying major development and operation risks related to the subject field. To take into account the impact of the surface facilities on the predicted field performance, a next-generation modeling approach was used to fully integrate the subsurface models with the surface model. Additionally, as the five-spot water injection pattern is the development scheme for one of the primary reservoirs, streamlines simulation using the integrated multi-reservoirs model was performed to define the performance of the different injection patterns and to rationally optimize use of the surface injection facilities. The subject multi-reservoir model was also used as a tool for risk mitigation plans for potential major gas production; different approaches were proposed and assessed in an attempt to define the possible plans for using the excess produced gas without negatively impacting the field's oil recovery.
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.
ADMA-OPCO is currently in the process of optimizing the development plans for several green offshore fields. This study addresses one of these fields, which consists of six stacked Thamama reservoirs (Fig. 1) planned to be developed through optimized individual reservoir development, water injection (reservoir model A), natural depletion (reservoir models B and C), and miscible gas injection (reservoir models D, E, and F).
The hydrocarbons will be produced through deviated-to-horizontal wells to be drilled from eight wellhead towers, which will be connected via subsea pipelines and risers to an offshore Super Complex where the hydrocarbons will be processed. From each wellhead tower, several wells are drilled targeting different reservoirs and tied to the same manifold, raising the concern of interference in flow of wells due to back pressure constraints.
The field will be developed as a gas self-sufficient field with no gas export line. As a result, full gas cycling is mandatory, which implies that all the produced gas will be used for fueling, gas lift, and the remaining gas will be re-injected.