Alusta, Gamal Abdalla (Heriot-Watt University) | Mackay, Eric James (Heriot-Watt University) | Collins, Ian Ralph (BP Exploration) | Fennema, Julian (Heriot-Watt University) | Armih, Khari (Heriot-Watt University)
This study has focused on the development of a method to test the economic viability of Enhanced Oil Recovery (EOR) versus infill well drilling where the challenge is to compare polymer flooding scenarios with infill well drilling scenarios, not just based on incremental recovery, but on Net Present Value as well.
In a previous publication (Alusta et al., 2011, SPE143300) the method was developed to address polymer flooding, but it can be modified to suit any other EOR methods. The method has been applied to a synthetic scenario with constant economic parameters, which has demonstrated the impact that oil price can have on the decision making process.
The method was then applied and tested (Alusta et al., 2012, SPE150454) with varied operational and economic parameters to investigate the impact in delaying the start of polymer flooding to identify whether it is better to start polymer flooding earlier or later in the life of the project. Consideration was also given to the optimum polymer concentration, and the impact that factors such as oil price and polymer cost have on this decision. Due to the large number of combined reservoir engineering and economic scenarios, Monte Carlo Simulation and advanced analysis of large data sets and the resulting probability distributions had to be developed.
In this paper the methodology is applied to an offshore field where the choice has already been made to drill infill wells, but where we test the robustness of the method against a conventional decision making process for which there is historical data. We do this by performing calculations that compare the infill well scenario chosen with a range of polymer flooding scenarios that could have been selected instead, to identify whether or not the choice to drill infill wells was indeed the optimum choice from an economic perspective.
We conclude from all the reservoir simulations and subsequent economic calculations that the decision to drill infill wells was indeed the optimum choice from an economic perspective.
Robbana, Enis (BP plc) | Buikema, Todd Alan (BP America) | Mair, Christopher (BP) | Williams, Dale (BP) | Mercer, David James (BP) | Webb, Kevin John (BP Exploration) | Hewson, Aubrey (BP) | Reddick, Christopher E. (BP)
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.
Brodie, James Andrew (BP Exploration) | Zhang, Pinggang (BP Exploration Operating Co) | Mellemstrand Hetland, Sigrun (BP Exploration Operating Company Ltd) | Moulds, Timothy Peter (BP plc) | Jhaveri, Bharat S. (BP Exploration (Alaska) Inc.)
BP has been operating gas injection projects in a variety of challenging environments throughout the world for more than three decades. Numerous innovative techniques have been used to optimize oil recovery and the results have been reported in a series of publications.
The focus of this paper is the North Sea, where BP operates offshore miscible gas floods in the Magnus and Ula fields and an immiscible gas flood in the Harding field. Tertiary miscible WAG in Magnus began in 2002 and its impact on reservoir performance is significant and well understood. More than 112 Bscf of gas have been injected into three mature panels, yielding 11.5 mmstb of oil at a very high net efficiency of 3.5 mscf/stb. The contribution of EOR to total field production has increased to 40% by 2010. In Ula, tertiary miscible WAG started in 1998 and has played a key role in arresting production decline. More than 23 mmstb of oil has been recovered by gas injection, which accounted for 60 - 70% of total field production in 2010. Key to the success of both projects has been securing a source of miscible gas and pursuing an active surveillance and reservoir management programme to monitor and optimize the flood.
The success of the North Sea projects is partly based on the experience of operating the world's largest miscible gas flood at Prudhoe Bay (Alaska), where conventional and unconventional techniques have been successfully applied in a variety of different settings. The knowledge acquired in Prudhoe Bay has been shared with other assets, including the North Sea, through a series of managed moves and master classes.
Miscible gas injection has generated considerable benefits for BP over the past three decades and will continue to do so in the future. The potential availability of large sources of CO2 in the future, through carbon capture, could help maintain a leading role for miscible gas injection for years to come.
North Sea gas floods
BP operates three large-scale offshore gas injection projects in the North Sea, namely the miscible gas projects in the Magnus and Ula fields and the immiscible produced-gas re-injection project in Harding field.
The Magnus field is located in the northern North Sea (see Figure 1). Magnus is operated by BP (85% equity) and is coowned by JX Nippon Exploration & Production (U.K.) Limited (7.5%), Eni (U.K.) Ltd (5%) and Marubeni North Sea Ltd
(2.5%). The field was initially developed by peripheral water-flooding. First oil was produced in 1983 and plateau production (150 mstb/D) was maintained until 1995, when sea water broke through at the crestal wells and severe barium sulfate scaling problems were encountered (see Figure 2).
Sand control, particularly gravel packing, is a common practice in the Mediterranean Sea due to the presence of poorly consolidated sandstone reservoirs. Open Hole Gravel Packs (OHGP) in highly deviated wells present an additional challenge due to the risk of sand bridging during the alpha wave propagation. The risk of bridging is escalated further in low fracture gradient environments where the pumping rate is reduced to avoid inducing losses. A major operator in Egypt has performed the first highly deviated OHGP jobs in the Mediterranean using Alternate Path screens. A series of qualification work was performed by the service provider during the planning phase for the 2 wells. Planning work included fluid rheology tests, flow loop testing, modeling full scale tests to achieve desired accuracy with gravel transport equations, pretreatment numerical simulations and post-treatment comparison of simulated data to actual data. Moreover, a lightweight proppant (LWP) product was qualified and successfully pumped on the second well where the fracture gradient was particularly low due to reservoir depletion. This paper discusses the planning, execution and post-job review work that was performed for these wells to produce two successful sand control jobs. Recommendations and lessons learnt for the future wells are also included.
With the Industry and specifically the Mediterranean Basin moving towards more challenging wells requiring sand control in ever higher deviations and significantly depleted sands these highly deviated gravel packs with high overbalances are becoming increasingly important to unlock resources and maintain field plateau.
The paper will detail the simulated results based on flow loop testing and how they compare with the actual job data. Successful sand control integrity was achieved with amount of gravel pumped exceeding 100% of the theoretical volume and sand free production achieved on both wells. Individual well performance with estimated skin values will also be shared.
The positional uncertainty about a point on a wellbore is commonly represented as an ellipsoid. The ellipsoid also accounts for the dimensions of the casing or open hole. Using this model, at any time the resulting uncertainty about a wellbore along its trajectory is a curved, continuous cone. To a good approximation, the intersection of the plane normal to a reference well with these cones can be represented as ellipses. This simple geometrical model has been adopted by various standards organisations to define minimum acceptable separation distances between well bores, for example the Norwegian NORSOK D-10 standard.
Because of mathematical difficulties, the existing methods for calculating the resulting separation factors are only approximations and may be either too optimistic or too conservative, particularly for ellipses with high eccentricities. The paper presents explicit equations for determining the exact condition where the ellipses touch, expressing the result as an expansion scale factor. Methods are presented for the expansion of either one, or both ellipses, together with implementation notes and other associated tools. The new algorithms are only marginally less efficient than the existing approximation methods and they can be used to increase the allowable proximity of two adjacent wells whilst satisfying the geometrical and probabilistic constraints. The examples included in the paper illustrate this.
The proposed calculation method is consistent with existing industry wellbore uncertainty models. Since the determination of the osculating condition is exact, the calculation is neither too optimistic nor too conservative. This paper is a response to discussions held at the SPE Wellbore Positioning Technical Section meeting on 3rd November 2011.
Zett, Adrian (BP) | Webster, Michael J. (BP Exploration) | Rose, Hilary (BP) | Riley, Stephen (Weatherford International) | Trcka, Darryl Eugene (Weatherford International Ltd.) | Kadam, Nilesh Subhash (Weatherford)
The Columbus basin offshore Trinidad is a mature hydrocarbon province. It contains multiple, stacked, discrete reservoirs which are supported and driven by complex displacement mechanisms. The reservoir surveillance challenges in the basin are compounded by the interaction of low salinity formation water, multiple fluid phases, thin beds, and completions that present difficult conditions for cased hole reservoir monitoring instruments.
Challenging current monitoring practices resulted in the implementation of new strategic measurements in the surveillance plan that delivered valuable insights and clarity to complex reservoir management problems.
The results obtained using existing procedures and technologies highlighted their shortcomings and uncertainties. To address these issues emerging technologies were evaluated under these challenging conditions. The results obtained clearly prove that tangible benefits could be realized through the use of the new surveillance techniques.
The benefits of applying new technology as part of an integrated surveillance strategy will be described in this paper. This new approach has helped reduce the uncertainty in both fluid contact movement and remaining hydrocarbon saturations. This has had a direct impact on reservoir simulation and the definition of future reservoir targets.
Gaudin, C. (Centre for Offshore Foundation Systems, University of Western Australia) | Randolph, M.F. (Centre for Offshore Foundation Systems, University of Western Australia) | Feng, X. (Centre for Offshore Foundation Systems, University of Western Australia) | Clukey, E.C. (BP Exploration) | Dimmock, P. (BP Exploration)
The BP gas business in Trinidad is a complex multi-field, offshore business which supplies several long term gas contracts. Assets comprise 10 producing fields, prolific reservoirs and high rate producing wells. Gas volumes are transported via a complex processing and transportation network. This complexity necessitated the need for an integrated dynamic model that accurately simulates the physics of flow through the reservoir, well and surface system to improve production forecasting and identify system optimization opportunities. IAM provides this simulation capability.
The IAM model combines Trinidad's complex facility network with hundreds of material balance and well models which allows for accurate simulation of flow through the system. This facilitates quantification of additional deliverability due to sequence optimization at any point in future production of the business.
IAM usage for production forecasting, scenario planning and for evaluating compression scenarios began in September 2008. IAM output analysis has informed several important business decisions such as choices around the continuity of the rig programmes, the timing and urgency of New Field Development options, the quantity and execution timing of opportunities required for gas supply, the cost and value of production capacity installed.
In this paper we discuss the process in building the Trinidad IAM model, learnings gathered from the model build and the future plans for using the IAM model for system optimization within bpTT.
Technical advances have led to both expansion and increased specialization in the engineering skills employed in our industry. In many cases, these specializations involve the use of complex engineering calculations involving a bewildering number of inputs and outputs to match real-world situations. Another problem with high-end applications is that they are costly and their logic is often presented as a "black box"--disclosure may be hampered by intellectual-property concerns. Although such high-fidelity applications may be essential for operations, simpler models with few inputs are better for scoping exercises or training.
The rapid and effective transfer of knowledge and experience to new hires with diverse backgrounds remains a key challenge. Though information technology and richer media have helped standardize delivery methods, accessing appropriate engineering applications for training purposes remains a challenge.
The important requirements are to communicate the fundamentals and build on knowledge gained at university. At the same time, the teaching methods and modules should instill curiosity and encourage critical assessment of the models and methods used. Therefore, the models should not be too far from reality.
Technical progress and refinement of a broad range of topics are inherent in the content and structure of the SPE paper library. The application to training is illustrated using examples including the simple 2D bottomhole-assembly (BHA) algorithm presented by Walker (1973). This paper shows how key refinements have been included by use of simple geometrical constructs and how the model has been used effectively in spreadsheet form to develop an understanding of BHA behavior and directional-survey-sag correction, and to identify and correct programmatic errors.
It is suggested that greater use can be made of the SPE library as a ready source of cost-effective training material and that the descriptions of the simpler engineering applications it contains can be recycled as valuable training aids.