In heavy oil reservoirs, water flooding leaves behind unswept hydrocarbon volumes due to unfavourable mobility ratios resulting in low ultimate recoveries. Increasing the viscosity of the injected water using polymer improves the water-oil mobility ratio resulting in improved recovery factors. This paper discusses for a large field in South Oman the successful implementation of a polymer flood project, the early results of Phase I and the planned expansions to Phase II and Phase III. Following a number of field trials and a series of laboratory studies, a full-field polymer project was implemented in the field in 2010. One of the key risks identified prior to starting the project was poor polymer injectivity. However, initial field results showed better injectivity than expected. Surveillance efforts are in progress to understand the better injectivity. The data analysis so far indicate that wellbore clean up due to polymer injection, improved as a result of improved mobility ratio and small scale induced fractures in some injectors are contributing to the improved injectivity. These factors enabled injection of more volumes of polymer than planned resulting in improved volumetric sweep efficiency and producer response. Results to date are encouraging, as after over a year of polymer injection, the oil gain due to the polymer flood is higher than expectation. Based on the initial results of Phase I, expansion phases II and III are being planned. Phase II is based on utilizing the available ullage in the system to accelerate the oil gain from polymer; it requires a relatively small upgrade of the existing infrastructure and surface facilities. Phase III is a full-field polymer flooding expansion combined with an intense infill drilling. Currently, a study is in progress to optimize the development concept for the infill wells and polymer flooding of Phase III.
Unlocking future development opportunities for brown fields are deemed to be a challenge from Urban Plan (UP) prospective. A field "A" of this paper subject is located south of Oman and was discovered in 1956. The reservoir in this field is a clastic formation divided into two main units; A and B, separated by a 10-15m thick lacustrine shale. The field is an onshore and is under waterflood since 1990s. The development of this paper subject was initially coupled with a nearby Field in the same cluster "Field B" for infill waterflood followed by polymerflood concept. The field development plan (FDP) calls for infill drilling in Inverted "9-spot" patterns with tighter well spacing in the Unit-A, convert corner Oil Producer (OP) to Water Injector (WI) and this development is to be associated with a totally new Urban Plan "revamp" that requires a demolition of the existing facilities. It also called for developing Unit-B through dedicated (twin) wells instead of comingling with Unit-A (to be supported by field trials). Moreover, selectively abandon horizontal producers in mitigating collision or interference risk with infill wells and to De-risk the full field polymer development through a new dedicated polymer pilot using new polymer molecular weight based on core flooding experiments data. The project was parked in 2014 at Decision Gate 3b (DG3b) because it was not economic with a very high Unit Technical Cost (UTC). Since then, great efforts were made by the Asset team to drive project competitiveness and be able to mature the project. Main steps achieved were; 1) de-risking/validating infill development concept by accelerating part of the FDP drilling scope utilizing the existed facility with very attractive economics; which unlocked an alternative full field urban plan concept of retrofitting instead of revamp resulted in drastic drop of project UTC, 2) Completing FDP proposed field extension appraisal scope (added additional 63 infill well locations), 3) Optimizing Water Treatment Plant (WTP) scope utilizing available field historical injection data, 4) Proposing Integrated Project Contracting Strategy (IPM) for drilling project wells to reduce drilling cost, 5) Proven comingling concept of Unit-A and B instead of twining through a dedicated pilot and 6) Successfully de-risked full field polymerflood development through a two years dedicated pilot. All these steps have led to successfully mature the project to Final Investment Decision (FID) in Q3 2020. This paper will demonstrate the key development challenges and risks, key steps made to validate/de-risk the proposed concepts before the full field implementation and the capital efficiency Journey to improve project competitiveness through an integrated subsurface and surface efforts.
Polymer outage (or polymer injection unavailability) is undesirable but also inevitable. When it happens, the question is how to respond to it to minimize its adverse impact on the production. This paper presents the rationale for generating a polymer outage strategy to operate a polymer flood field in the southern area of the Sultanate of Oman. The work presented here is based on field performance and analytical analysis. The diagnostic plots were created from 10 years of polymer flood field response and were used for this operating decision. The pros and cons of two scenarios were discussed. The selected operational strategy is to minimize the short falls of polymer outage. The strategy was implemented in the field. Simultaneous injection and production pause (SIPP) is recommended for the full field polymer outage. It minimizes the impact on polymer incremental oil and hence less deferment. Calibrated with the actual results, analytical method is used to determine when to shut down and whether a short of buffer period of water can be tolerated before SIPP is carried out. The polymer literature focus on polymer mechanisms, modeling, project initiation and implementation but no paper discusses the operational strategy on how to respond to field polymer outages. This paper shares our operational learnings and the field results of various polymer operation modes on polymer incremental oil. The learning from this field may be of interest to other operators who are planning or currently implementing polymer flood in their fields.
Enhanced oil recovery through injection of a solution of water and polymer is becoming a mature chemical flooding technique. In general, reservoirs with mature water-flooding projects offer an excellent opportunity for extension with polymer injection as uncertainties associated with reservoir connectivity and injection potential are already substantially reduced. For our particular reservoir an additional fortunate circumstance includes an ongoing polymer injection project in an adjacent reservoir which enables easy field testing given the local operational challenges and circumstances. This paper presents ongoing work related to improving ultimate oil recovery from an active water flood project by polymer injection where a polymer flooding pilot is already ongoing. The work includes studies to extend the existing polymer injection facilities of a nearby polymer project to this rather different, in geologic terms, Precambrian reservoir with much lower permeability, oil saturations and significantly more layered reservoir architecture. Geological and petrophysical workflows together with dynamic modeling history matching iterations resulted in reducing subsurface uncertainties such as the distribution of permeability and initial oil saturation. Reservoir compartment connectivity and sweep efficiency are constrained by matching pressure and injection, as well as, production data from 180 wells. Polymer injection feasibility is proven through: dynamic modeling, laboratory experiments, ongoing polymer injection pilot and adapting learning’s from the ongoing adjacent polymer project. The study reveals that a polymer injection project is economically feasible under a range of subsurface and costs scenarios.
A number of thermal developments are currently in execution in Oman. Two of these are located in South Oman and contain an exceptionally thick column (200m+) of heavy oil (200 to 400,000 cp) in Cambrian reservoirs at a depth of 1050 m below surface, underlain by a moderately strong aquifer. One of the fields has been in production for 20 years, the main production mechanisms are pressure depletion and natural ingress of aquifer water, while the other field has only produced a small amount by cyclic steam stimulation (CSS) trials due to the high viscosity of its heavy oil. For the next phase of development a vertical well pattern re-development is planned which will increase the ultimate recovery significantly, through a combination of cold production, CSS and steam flooding. The thickness of these reservoirs is unusually large for steamflooding and this poses both opportunities and challenges. There are no direct analogues and the industry practices of managing a steamflood in this specific setting is yet to be verified. Phase I deliberately addresses only the upper parts of the reservoirs while significant volumes are still to be matured in a future Phase II development. Following some higher level screening work of recovery mechanisms, the realistic development options for Phase II are innovative application of further steam flooding. Subsurface uncertainties are actively managed by different means; among them are the steam injection trials and steam pilot. The full field developments planned to start-up with Phase I in 2012 followed by Phase II in 2017. The paper will provide an overview of the proposed Phase II thermal development and specifically the innovative way development challenges are addressed. The integrated modeling work that yielded a better design of well completion strategies will be discussed. Additional topics addressed include minimising additional gas requirements through application of co-generation of electricity and steam (COGEN), water management and overall integrated project management.
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