This paper presents a success story covering the design, execution and post job evaluation of drilling and completing two Maximum Reservoir Contact (MRC) pilot wells. The wells were drilled and tested as part of a pilot wells programme aimed at proving-up to the well architectures planned to be introduced on a field wide basis. The carbonate field lies offshore Abu Dhabi in relatively shallow waters. Prior studies have confirmed the viability of continuing development of the field from artificial islands (drilling and production centers) by utilizing Extended Reach Drilling (ERD) and MRC well technology. The effectiveness of the MRC wells is critically dependent on well planning, design and placement in the reservoir interval. The paper describes the integrated workflow and well optimization process that have been applied to the two pilots which cover the following steps:Model developmentSimulation for completion options screeningProduction prediction by coupled reservoir-well dynamic simulationFlow assuranceAssessment of coiled tubing and wireline accessibilityDrilling and completions engineering analysis, time, cost and risk assessment. The application of this process has led to a number of (local) well records, firsts and learning’s that can be applied to future wells. The paper also summarizes the post drilling evaluation activities, which included running of production logging tools to optimize acid stimulation, an extensive flow test and data gathering program, and well model construction and validation to closely monitor and assess well performance.
This paper presents an application of integrated asset modeling to a giant offshore oil field. The field is located northwest of Abu Dhabi Island and is one of the largest offshore fields in the world. The asset comprises several individually modeled reservoir layers sharing a common surface facility. The traditional method of modeling this field involves running separate simulation models assuming fixed boundary conditions at the wellhead. This does not accurately model the effects of the constraints imposed by the surface facility. The primary aim of this paper is to highlight the importance of integrated asset modeling in formulating an optimized, cost- effective development plan. This is achieved through the provision of realistic production profiles, taking into account the impact of system backpressure and changes in operating conditions. Secondly, integrated modeling acts to reduce uncertainty in the design data in terms of phased production for future facility upgrading and replacement. Finally, integrated modeling provides a framework for production system optimization under different development schemes. Included in the discussions presented here are a validation of the integrated asset modeling tool, an overview of the business requirements for the operation of the field over the next 30 years, and analysis of selected development strategies highlighting the added value of integrated asset modeling. The results of the integrated studies helped to formulate decisions on infill drilling based on realistic production profiles. Secondly, they served to reduce risk through better understanding of the surface and subsurface interaction. Thirdly, they helped to support the decision for commissioning a new concept facility layout (artificial islands), which represents a significantly lower CAPEX investment with more flexibility. Finally, the integrated study assisted in making decisions on the application and type of artificial lift and displacement mechanisms. Introduction The exploration and production of hydrocarbons encompasses numerous scientific and engineering disciplines including geosciences, reservoir, production, and facilities engineering. It is widely recognized that integration of these discipline silos is of key importance in optimizing the profitability of an oilfield asset. Information technology is a key enabler in each engineering domain. Numerous workflow and simulation software products have evolved over the past 30 years that have led to significant productivity and recovery improvements. Complex reservoirs are modeled more easily, multiphase flow is simulated, and performance and sizing of equipment may be optimized. This paper aims to highlight the importance of integrated asset modeling in the FEED and field development planning processes of a giant offshore oil field. The asset under consideration here is one of the largest of its type in the world covering an areal extent of 1,200 square kilometers. There are three distinct reservoir strata producing through approximately 450 single and dual string wells. The three major reservoirs, Reservoirs I, II, and III, are geologically characterized as multiple carbonate layers separated by impermeable strata. Each reservoir has its own layering scheme with different vertical and lateral permeability distribution and thickness. The northeast area is generally highly faulted and fractured. These geological features result in different well productivities and completion types. The field was initially developed with a peripheral waterflood strategy. Subsequently, five spot pattern and staggered line drive water injection schemes were introduced. Ongoing field development planning studies call for intensive infill drilling and application of artificial lift and/or Enhanced Oil Recovery (EOR) to different reservoir areas.
Abu Dhabi Company for Onshore Oil Operations (ADCO) is a major oil producer in the Arabian Gulf with a wide portfolio of fields and reservoirs. The company is currently developing both new and existing assets to increase its production capacity. Field 'M' is one of the new assets that will contribute to this additional production.Although the field was discovered in 1975, it was categorized as a marginal development primarily due to its remote location, limited size and reservoir properties. As a result it remained undeveloped until 2011. A 3D seismic reprocessing was conducted in 2009, and significant reservoir data was gathered from an appraisal well in 2010 which reduced the subsurface uncertainties. The field became less remote through the development of a larger, neighboring field 50km away. As a result, in 2011 a decision was made to carry out a full field appraisal campaign, with the aim of putting the field on production by 2017.This paper describes the main challenges of the appraisal and development of the field, and details how they were tackled. A special emphasis is put on the value of multi-discipline integration between all the project stakeholders.
Field A is a giant field consisting of many sub reservoirs in Abu Dhabi offshore environment, having produced for 50 years mainly through peripheral water injection. The filed considered in this study is planning to build the long-term development plan aiming to extend production plateau by a further 25 years through infill drilling and water flood enhancement. This paper will describe an approach for optimizing the number and type of drilling centres required to enable the development plan to be flexible in design to accommodate a number of infrastructure, facilities, drilling and subsurface constraints. The proposed reservoir development scheme is to progressively expand from the on the current peripheral water injection to enhanced water injection phase requiring line drive and pattern flooding. The project requires integration of around 180 new wells to be drilled with the associated injection and production facilities into an existing brown field complex with more than 1000 wells, kilometres of pipelines including well head towers and artificial islands. In addition the project requires having flexibility to expand for later field development schemes that could include further infill and EOR phases. The key challenge for the development plan is to assess the impact of drilling feasibility and the number of drill centres within the constraints of the existing brown field infrastructure and how it impacts on the production profiles, cost, project feasibility and value. Analysis and selection of number and location of drilling centres are essential requirement for finalizing the optimal development. An integrated subsurface, surface and drilling feasibility assessment analysed several different drilling centre scenarios involving various combinations of artificial islands and well head towers. Different drilling and completion duration were calculated based on drilling complexity and feasibility for the different development plan scenarios. The impact on the production profiles were assessed based on reservoir simulations using the well delivery timing for each scenario. The final screening assessment of the different field development scenario included inputs and constraints from infrastructure, facilities, sea-bed complexity, HSE, flexibility and project economics. The major findings are followings: (1) field development planning requires integration of different functions and disciplines early in the project phase before entry into Select stage, (2) important to test the feasibility of drilling and its impact on the field development concepts and production profiles, and (3) the results indicated the preferred development plan that best meets the objectives is based on a combination of artificial islands and well head towers. The preferred development plan will utilizes a novel combination of artificial islands and well-head towers that enables flexibility and expandability to meet the development plan objectives of extending the production profile and provide a foundation for long term asset replacement.
The procedure presented in this paper offers a way to combine and integrate black-oil PVT data obtained from several wells at various depths in a consistent and easy manner, especially when the PVT properties exhibit variation with depth and an EOS model is not readily available. In principle, it is similar to normalizing and de-normalizing SCAL data. Although the method was primarily intended to honor and consistently take into account vertical variation of black oil PVT properties, it can also be used to reliably estimate oil PVT properties at elevations close to the GOC where reliable fluid sampling may not be possible due to gas coning or cusping during sampling operation. The following are the main benefits of the method:Detecting and representing vertical variation of fluid properties in a reservoir or compartment especially when access to an EOS package is not readily availableVerifying reservoir compartmentalization by identifying lateral variations in PVT propertiesValidating PVT parameters and their variations with depthGiven sample PVT data from various depths, generating representative black oil PVT tables at any required depth for use in black oil simulation Summary Presented procedure is a recently modified version of the original concept that was first introduced in 1981(1) for analyzing black-oil PVT data and generating PVT properties for black oil simulation. With recent modifications, the concept has been improved for pressures above the bubble point pressure. It has ben applied to several ADCO reservoirs with satisfactory results. Recently, it was applied on a new reservoir that has a gas cap and exhibits fluid properties variation with depth. First, bubble point pressures of PVT samples taken from different depths and initial reservoir pressure measurements from MDT or RCI runs and other tests are plotted and correlated to depth. The bubble point and initial reservoir pressure vs. depth plots are used together to estimate or confirm the GOC depth as the intersection of the two pressure variations. Next, as explained in the following sections, for each sample included in the analysis, black oil PVT properties above and below the bubble point pressure are normalized and correlated to normalzed pressure. Eventually, PVT properties are denormalized at "selected depths" to generate the black oil PVT tables needed for black oil simulation.
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