Clair Ridge will include the first offshore deployment of BP's reduced salinity LoSal ® enhanced oil recovery (EOR) water injection technology. Over the last ten-years, there has been significant growth in the evidence supporting the use of low salinity water injection as a viable EOR process. BP, by using its LoSal EOR technology, has shown that incremental increases in oil recovery can be achieved across length scales associated with core flood experiments (inches), field-based single well chemical tracer tests (feet) and field trials (inter-well distances). This paper discusses the process undertaken by the Clair Ridge project in getting LoSal EOR adopted as a day one, secondary waterflood. Confirmation and quantification of the LoSal EOR potential at Clair Ridge began in 2006 with completion of a series of core floods using three reservoir rock types. However, it was recognised that as a green field development single well chemical tracer tests or field trials were not possible ahead of sanction. Therefore, confidence in the materiality of recoverable oil by using LoSal EOR was built through integration of core flood data into reservoir simulation studies focused on a thorough investigation of the subsurface, produced water disposal and reverse osmosis operability uncertainties. In parallel, scoping facilities studies were completed to provide cost, weight and footprint estimates for inclusion of a 145 mbd RO plant on the platform. Finally, and critical to the success of this project was early and open partner engagement in LoSal EOR evaluation.
Summary Core tests demonstrated that decreasing the salinity of injection water can increase oil recovery. Optimizing injection-water salinity, however, would offer a clear economic advantage for several reasons. Too-low salinity risks swelling of the clays that would lead to permanent reservoir damage, but evidence of effectiveness with moderate-salinity solutions would make it less difficult to dispose of produced water. The goal is to define boundary conditions so injection-water salinity is high enough to prevent reservoir damage and low enough to induce the low-salinity (LS) effect, while keeping costs and operational requirements at a minimum. Traditional core-plug testing for optimizing conditions has some limitations. Each test requires a fresh sample; core-testing requires sophisticated and expensive equipment; and reliable core-test data require several months because cores must be cleaned, restored, and aged before the tests can begin. It is also difficult to compare data from one core with results from another because no two cores are identical, making it difficult to distinguish between effects resulting from different conditions and effects resulting from different cores. Gathering statistics is limited by the time required for each test and the fact that core material is in short supply. Thus, our aim was to explore the possibility of a less-expensive, faster alternative by probing the fundamental chemical mechanisms behind the LS effect. We developed a method that uses atomic-force microscopy (AFM) to investigate the relationship between the wettability of pore surfaces and water salinity. We functionalize AFM tips with organic molecules and use them to represent tiny oil droplets of nonpolar molecules, and we use sand grains removed from core plugs to represent the pore walls in sandstone. We bring our “oil”-wet tip close to the sand-grain surface and measure the work of adhesion between the tip and the surface. Repeated probing of the surface with the tip produces data that one can convert to maps of adhesion, and we can estimate contact angle. Adhesion work is proportional to wettability and is directly correlated with the salinity of the fluid in contact with the tip and the particle surface. From our measurements, the threshold values for the onset of the LS response are 5,000 to 8,000 ppm, which benchmark remarkably well with observations from core-plug tests. From a mechanistic perspective, the correlation between salinity and adhesion provides evidence for the role of electrical-double-layer (EDL) expansion in the LS response; expansion of the double layer decreases oil wettability. Because AFM experiments can be performed relatively quickly on very little material, they give the possibility of testing salinity response on many samples throughout a reservoir and for gathering statistics. Our approach provides a range of data that one can use to screen conditions to maximize the value of the core-plug testing and to provide extra data that would be too time consuming or too expensive to gather with traditional methods alone. Thus, AFM force mapping is an excellent complement to traditional core-plug testing.
This paper documents key learnings from BP's experience in managing the risks associated with deploying LoSal waterflooding technology over the past five years. The paper covers the management of technical risk, operational risk, organisation and resourcing risk, and the risk of failing to secure adequate engagement with decision-makers. The learnings described in the paper cover experiences gained over multiple projects over different stages of project cycles, including the application of LoSal EOR in onshore and offshore settings, in existing waterflood operations as well as new projects. On the technical side, the derivation of quality coreflood data, and its calibration with both pilot and single well chemical tracer test data have been key for building confidence in the magnitude and uncertainty of the LoSal response. Operational risk management has been essential for securing approval for implementation of LoSal EOR. Risks evaluated include loss of injectivity, operability of desalination facilities, and the interface with produced water management. A common learning is the need for building contingency into project design to cover all of these risks. Organisation and resourcing have required careful consideration, and have been addressed by having a central team conduct LoSal EOR evaluations for multiple assets, in order to make the best use of scarce/critical skills. Finally, organised and thoughtful engagement with decision-makers has been critical. Securing approval has required a careful and sustained effort, because the concept of LoSal EOR is relatively new, spans multiple disciplines, and often enhances, but does not always enable, new project economics. Following a careful approach to risk management, LoSal waterflooding has been internally approved for two new offshore projects, key steps in building confidence for the wider application of the technology.
This paper details the progress made with the implementation of BP's FIELD OF THE FUTURE program over the past four years. It first describes the approach taken by BP to install real time data infrastructure in many sectors of its operations. To date this infrastructure has included the installation of 1800km of fibre optic cable, the registration of nearly two million real time data tags within a common real time data backbone, and construction of more than twenty Advanced Collaborative Environments supporting production and drilling operations. The paper then describes some of the activities underway in BP's operations, and the associated benefits, including:use of advanced well monitoring technology to manage sand production and other aspects of well performance in 20 fields (1–3% production benefit)examples of full field optimisation/visualisation and associated benefits (1–2% production benefit)the development of a new downhole flow control capability for high rate sand prone wells (resource/reserve benefit)early experience with the application of temperature profile monitoring and of life of field seismic (resource/reserve benefit) Finally, the paper describes the people, process and organisation activity undertaken in several of BP's large operating areas which have directly impacted many of the operational staff working in these areas through an extensive set of change management workshops and similar activity. The lessons learned from these activities over the past four years include the need to:define support and maintenance resources up frontidentify and standardize infrastructure requirements for new projectstake a centralized global approach to planning deployment but a local approach to implementationfully resource change management activity 1. Background to BP's FIELD OF THE FUTURE Program BP's FIELD OF THE FUTURE program (Ref 1) was established in 2003 with an initial focus on engagement and deployment, the objective being to deploy core technologies in a limited number of assets in order to build a track record, to re-affirm the prize and to build a technical and architectural foundation for subsequent 'bigger moves'. These early deployments, conducted over the period from 2003 to 2005, confirmed the potential of the program to add significant value across a broad range of asset types. Since that time the program has evolved to focus on the three areas, as described pictorially below in Figure 1. The common feature of most of the elements of the program is that they are related one way or another to real time data, and are aimed at high rate fields which form a significant part of BP's current and future portfolios. BP is also working on high well count fields onshore in North America where cost effective solutions for optimization of gas well deliquification is the focus. These and other technologies generally impact production, recovery or both. Over the next 10 years or so, it is expected that the program will contribute in excess of 1 billion barrels of recovery and 100 M/bd to BP's E&P segment.
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