This paper describes preparations and planning for a campaign of foam gas shut-off pilot operations in a large carbonate reservoir located offshore Abu Dhabi containing an oil column in equilibrium with a large gas cap. Throughout the field history and due to the heterogeneity (permeability ranges from 5 mD to 1 D), the major challenge to produce the oil rim independently from the gas cap was how to control premature gas breakthrough in the oil producers. Mechanical interventions in high gas-oil ratio wells are particularly complicated due to the risk of losing oil potential and are generally unsuccessful.
Injection of foam for gas shut-off (FGSO) is a near-wellbore treatment, which has been trialed elsewhere in the industry with some success. Foam can act as an auto-selective agent to shut-off confined gas inflow through a gravity-controlled source like coning or cusping, while oil breaks the foam, resulting in preferential oil flow and reduction in gas-oil ratio. In addition, this type of operation has been identified as an EOR enabler, because it can help prepare for the technical and logistical challenges of using EOR chemicals in the field, generate data useful for the modeling of surfactant and polymer under reservoir conditions, and mitigate early gas breakthrough in the case of gas-based EOR developments.
For the reservoir in question, a key complicating factor was to identify a surfactant, which could generate strong foam in-situ (mobility reduction factor of 50) at harsh reservoir conditions (temperature of 220-230 °F and water salinity above 200,000 ppm, including 20,000 ppm divalents), with an acceptable level of adsorption. The candidate selection process took into consideration overall behavior of the reservoir as well as performance of the individual high-GOR wells. Target well selection criteria included homogeneity of permeability, an understanding of gas sources and their movement, and observation of a rate- or draw-down-dependent GOR.
The experimental lab program involved testing several surfactant formulations in bulk as well as in corefloods with and without the presence of reservoir oil to evaluate foaming ability and level of gas flow reduction. One formulation showed the right level of in-situ mobility reduction, in addition to stability and moderate adsorption at the prevailing reservoir conditions, and was therefore selected for a pilot test involving four wells.
Torres, Javier (ADNOC) | Hernandez, Eglier (ADNOC) | Kadoura, Olla (ADNOC) | Zidan, Maher (ADNOC) | Uijttenhout, Mattheus (ADNOC) | Al Harbi, Ahmed (ADNOC) | Al Hammadi, Yousef (ADNOC) | Al Zaabi, Mohamed (ADNOC) | Draoui, Elyes (ADNOC) | Ghauri, Usama (ADNOC) | Saeed, Osama (ADNOC) | Al Katheeri, Yousif (ADNOC) | Ismail, Jawad (ADNOC) | Qambar, Najem (ADNOC) | Beaman, Daniel (ADNOC) | Salimov, Rail (ADNOC) | Nes, Knut (ADNOC)
An integrated and collaborative study was required in order to determine the most cost effective field development scenario while ensuring collision risk mitigation, to define and validate the well planning and slot allocation for the wells scheduled for the next ten years as part of the redevelopment due to a new subsurface strategic scheme that was later extended to the full lifecycle of a green field offshore Abu Dhabi. The workflow included data, feedback and participation of four main stakeholders: Subsurface Team, Petroleum Engineering Team, Drilling & Completion Team and Surface Facilities Engineering Team. The process started with the provision of the targets by the Petroleum Engineering Team, previously validated by the Sub-Surface Team to the Drilling & Completion Team. The second step included generation of preliminary trajectories including high-level anti-collision analysis against existing wells as well as other planned wells; this step also included validation of the Completion requirements based on the preliminary drilling schedule and equipment availability. The trajectories were then sent back to the Petroleum Engineering Team for well objectives validation and finally a multi-disciplinary session with the Surface Facilities Engineering Team, Petroleum Engineering Team and Drilling & Completion Team was executed to ensure readiness of surface installations based on the drilling schedule; as part of the outcome of this session multiple iterations occurred until alignment and agreement of all the stakeholders was achieved. The outcome of the workflow was the generation of full field development study including the preliminary trajectories, their respective slot allocation, high-level anti-collisions and estimated Drillex (Drilling Capex) validated and agreed by all stakeholders. This novel approach to the integrated multi-disciplinary collaborative field development well planning provides multiple benefits such as: 1. Fast delivery of scenarios for field development well planning, reducing the cycle time to less than half of the conventional time required.
Field presented here is located in offshore Abu Dhabi, consisting of multi-stacked reservoirs with different fluid and reservoir properties. In this paper, field development plan of one of reservoir has been presented which was initially planned to be developed with pattern water injection by more than 50 horizontal wells penetrating all the ten oil bearing layers from 9 well head towers. Reservoir consists of under-saturated oil with low gas-oil ratio and low bubble point. Initial 2 years of production was considered as Early Production Scheme (EPS period), during which significant amount of early production data consisting of downhole pressure measurement, time-lapse MDT, vertical interference data, PLT have been collected. Based on EPS data simulation model has been updated. Simulation fits well with the observed pressure gauge and time-lapse MDT data. Updated model gives good prediction for a year of blind test data (including saturation, MDT and porosity) collected from different wells several kilometers away from current development area reflecting a high level of confidence in areal and vertical connectivity representation. Considering other reservoir uncertainties different Development plans have been screened using updated model in order to improve recovery factor and economics. Based on development plan screening study, optimized development option has been chosen for Full Field Development.
Short-term production and injection optimization are best approached from an integrated surface/subsurface perspective, recognizing that well performance is driven by competition for an existing network hydraulic capacity.
This paper presents a tool for real-time optimization (RTO) of water-injection systems at the scheduling time scale (i.e., days to months). Its development stemmed from the observation that operations such as pigging or shutting manifolds for rig activity might disrupt the injection network balance; hence, injectors would benefit from quick control readjustments. Furthermore, an existing network is not necessarily able to distribute available water where desired, and control compromises best found by an optimizer should be sought.
It is assumed that reservoir conditions are stationary, and injection targets at any level of granularity (well, reservoir segment, or field level) have been established based on subsurface requirements. By use of performance curves for each injector and either a simplified or a full-fledged network model, the algorithm finds a set of optimal well controls with a steepest-descent method implemented in Microsoft (2016) Visual Basic for Applications (VBA). The interface is spreadsheet-based, facilitating updates in well-performance data or changes in reservoir requirements. When needed by the algorithm, a third-party hydraulic-flow simulator able to balance the system from the injection modules down to the manifolds is called through an application programming interface.
A case study is presented, illustrating how the tool has been used to estimate the benefits of installing wellhead chokes on the currently more than 200 active injection strings of a giant oil field offshore Abu Dhabi.
Jitendra Kumar, Pawan Agrawal, and Elyes Draoui, Abu Dhabi Marine Operating Company Summary Hydrocarbon-gas injection is one of the most widely applied processes in the oil industry and is a promising enhanced-oil-recovery (EOR) method for use in Middle East carbonate oil fields. Gas injection improves the microscopic-displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can negatively affect the ultimate recovery because of viscous fingering and gravity override. This paper describes two gas-injection pilots that have been implemented in offshore Middle East carbonate reservoirs: a secondary and a tertiary gas injection through line drive to assess injectivity, productivity, macroscopic-sweep efficiency, flow assurance, and operational efficiency in a field that has a long water-injection history. A strong monitoring plan, including an observer well, was applied through time-lapse saturation logging, pressure measurements, production testing, and a tracer campaign to evaluate the pilot efficiency and address key uncertainties upfront before full-field application. This paper describes the pilot performance in the context of full-field development, local-and macroscopic-displacement efficiency, flow-assurance issues, and operational learnings. The gasinjection performance is strongly affected by reservoir heterogeneity, gravity segregation, and the existing pressure gradient, and the history match performed indicates near-miscible or miscible behavior depending upon local pressure regimes, which thus govern the ultimate recovery. The history match also shows that for the same pilot, performance can be further improved through water-alternating-gas (WAG) injection, resulting in a viable development scheme for full-field implementation. Original manuscript received for review 28 September 2015.
The considered giant carbonate field is located offshore Abu Dhabi and has 50 years of production history through a series of pressure-maintenance methods. Chronologically, the implemented development approach includes gravity-driven dumpflood water injection, peripheral water injection, and immiscible crestal gas injection and a review of these methods is discussed in
The integrated development plan consists of (a) review of past gas injection pilots, (b) injectant screening based on experimental results, (c) injection scheme selection to maximize the recovery, (d) configuration of the EOR pattern, (e) EOR application timing and rate optimization considering interaction with current development plan, and (f) investigation of surface facility requirements for EOR development.
A sector model study was done, using inputs from the SCAL and PVT experiments, for the screening ((b) and (c)) using the past pilot review (a). Learnings from the sector model simulation is deployed to the full field EOR application by dividing the field on the basis of maturity to water flood and historical development footprint, respecting the simplicity in EOR application without jeopardizing the ongoing production. Through simulation exercises, an integrated EOR plan was built ((d) and (e)). The proposed EOR plan efficiency is evaluated through full-field reservoir simulations, which takes practical drilling plan, well completion types and surface facilities constraints.
The simulation results demonstrated that the proposed plan (a) can recover oil without bypassing remaining oil, (b) can achieves 70% recovery based on selected gas, (c) is vigorous in terms of well count and well-head tower, and (d) utilizes the available surface facilities resources at maximum. The methodology used to design and evaluate the EOR development plan is applicable to other similar fields.
Hydrocarbon gas injection projects are undertaken in order to maintain reservoir pressure, produce oil through swelling and reduce residual oil saturation by decreasing the interfacial tension (IFT). Along with local displacement efficiency, macroscopic sweep efficiency plays a dominant role in the success of gas injection projects, as recovery from the field depends strongly on reservoir geology and petrophysical properties.
In this paper, a case study of one of the hydrocarbon gas injection pilots is discussed as the performance of the other two pilots has already been described in
This paper presents the overview of the pilot, monitoring plan and the findings which include microscopic and macroscopic sweep efficiency. The pilot areal sweep performance was affected by the existing pressure gradient of peripheral water injection while the vertical sweep efficiency was strongly affected by the reservoir heterogeneity. At the cessation of the pilot, a value of 6 ± 3% was measured from SWCTT in the producer well, which shows the robustness of the gas local displacement efficiency. The history match performed indicates that for the same pilot, the performance can be improved using horizontal line drive in place of five-spot pattern and it can further be enhanced through water-alternating-gas (WAG) injection. The learning from the three gas injection pilots is used in re-designing the future large-scale development plan and is described in details in
Su, Shi Jonathan (Schlumberger) | Patacchini, Leonardo (Abu Dhabi Marine Operating Company) | Mohmed, Farzeen (Abu Dhabi Marine Operating Company) | Farouk, Magdy (Abu Dhabi Marine Operating Company) | Ouzzane, Djamel (Abu Dhabi Marine Operating Company) | Draoui, Elyes (Abu Dhabi Marine Operating Company) | Torrens, Richard (Schlumberger) | Amoudruz, Pierre (Schlumberger)
Coupling is performed periodically at the wellhead, using a reservoir simulator in which the field manager controls the reservoir models by supplying well constraints and controls the network models by supplying well performance curves. Allocation strategies and pressure and flow constraints are imposed by the field manager, for which the different sub-models are black boxes; the models themselves are controlled hydraulically without embedded production or injection constraints. This explicit approach has been selected for its flexibility. In particular, by expressing rates at the surfacesubsurface interface at standard conditions, it is possible for the two reservoir models to have different equations of state and different treatments of injected water salinity, while the surface models use a blackoil fluid description. This project required ensuring rate continuity at the transition from history to forecast for over 600 active production and injection strings, even when the reservoir and network models are not perfectly historymatched. This was achieved by introducing pressure shifts in each vertical flow performance curve to ensure continuity of the choking margins (i.e., differences between wellhead pressures and backpressures) and by overriding the default guide rate flow allocation method of the field manager to prevent abrupt changes in the production split of wells currently producing below potential. The use cases described here are based on an eight-year (2015-2023) drilling schedule followed by no further activity. We focus on assessing the impact on production and injection arising from: replacing pipelines or changing network topologies; relaxing the constraint of producing at initial solution gas-oil ratio with and without reduction of separator pressures; and redistributing or increasing the water injection capacity. 2 SPE-183153-MS
Carbon dioxide (CO2) injection is considered to be a viable option for enhanced oil recovery (EOR) and has already been implemented commercially for more than 40 years. However, the applications are limited to onshore and offshore application for EOR activities have not yet been implemented. This paper presents the subsurface evaluation using laboratory experiments (PVT and corefloods) and compositional modeling, the design and surveillance program of a CO2 pilot project planned in a carbonate reservoir located offshore Abu Dhabi.
PVT and coreflood experiments demonstrate the local displacement efficiency of CO2 in tertiary mode due to gas-oil miscibility, swelling of oil and reduction in oil viscosity. The screening study performed using a tuned equation of state (EOS) predicts significant additional recovery in a previously waterflooded area. A pilot is planned in one of the reservoirs of the field, which has 40 years of peripheral seawater injection history. The pilot design is influenced by existing peripheral pressure gradient, and is located down-dip in the field that covers approximately 80 acres. The pilot location is selected based on geology, reservoir quality, maturity to waterflood and surface facility constraints. A comprehensive reservoir surveillance plan, including one to two observers well, is developed to monitor pilot performance. The planned pilot will reduce uncertainties and risk associated with CO2 injection and address bottleneck uncertainties in an offshore environment before large-scale application.
The first offshore CO2 injection pilot is designed for implementation in a tertiary mode in a giant carbonate field, which is still under secondary recovery production, to minimize interaction with current production and impact on surface facility. The paper also presents the possible mitigation for various challenges identified like asphaltene, scaling, corrosion, impact on existing carbon steel well completion, etc. associated with CO2 injection.
The methodology and technical analysis used to evaluate and design the CO2 pilot are applicable to other potential fields in the region.
Hydrocarbon gas injection is the most widely applied process after waterflooding, and is a promising enhanced oil recovery (EOR) injectant for use in Middle East carbonate oil fields. Gas injection improves microscopic displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can negatively impact the ultimate recovery due to viscous fingering and gravity override.
This paper describes two gas injection pilots that have been implemented in offshore Middle-East carbonate reservoirs, a secondary and a tertiary gas injection through line drive to assess injectivity, productivity, macroscopic sweep efficiency, flow assurance and operational efficiency in a field that has long water-injection history. A strong monitoring plan, including an observer well, was applied through time-lapse saturation logging, pressure measurements, production testing, tracer campaign, etc. to evaluate the pilot efficiency and address key uncertainties upfront prior to full-field application.
This paper describes the pilot performance in the context of full-field development, local and macroscopic displacement efficiency, flow assurance issues, and operational learnings. The gas injection performance is strongly impacted by reservoir heterogeneity, gravity segregation and the existing pressure gradient, and the history match performed indicates near-miscible or miscible behavior depending upon local pressure regimes, which thus govern the ultimate recovery. The history match also shows that for the same pilot, performance can be further improved through water-alternating-gas (WAG) injection, resulting in a viable development scheme for full-field implementation.