Drilling and Completion of Depleted Carboniferous Reservoirs in the U.K. Southern North Sea
Abstract: The objective of this paper is to outline and discuss the learnings which improved the drilling and completion process of horizontal wells in depleted Carboniferous reservoirs. The learnings were derived from three replacement wells drilled and completed on the Conoco (U.K.) Limited operated Murdoch Field, which is a mature development in the Quadrant 44 area of the United Kingdom Southern North Sea (UK SNS) (refer to Figure 1). The replacement wells were drilled in an effort to restore producti… Show more
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Cited by 5 publications
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Formation damage during drilling and completion has often led to poor well test results and, in many cases, the wrong conclusions have been drawn. Poor productivity has been mistaken for poor permeability and connectivity. Reservoir potential has been hidden and assets abandoned. However, the recognition of formation damage in unwanted assets has led to the re-evaluation of legacy drilling and production data. Two examples are presented which demonstrate the methodologies and techniques employed in an integrated solution for the recognition, diagnosis and mitigation of formation damage. In particular, return permeability tests on core in the laboratory are essential but must be coupled with a more rigorous validation of well test interpretations before reaching any decision on relinquishment or abandonment. An integrated petrophysical, geomechanical and formation evaluation strategy can open up significant development opportunities in what were regarded as uneconomic oil and gas fields. In one case, the methodology resulted in a ten-fold increase in absolute well flow potential and the commercial development of the field. The methodologies and workflows developed in these field examples mean that it is possible to drill and develop low permeability reservoirs economically without causing damage and avoiding the need for expensive stimulation through careful planning and design. Introduction Formation damage can be defined as any reduction in near wellbore permeability as a result of drilling, completion, production, injection, attempted stimulation or any other well intervention. The total cost to the industry in deferred production and remedial damage treatments is difficult to quantify. However if one were to extrapolate from the examples described in this paper, revenues worth billions of dollars are potentially overlooked due to poor characterisation of formation damage. Certainly, efforts continue to be made to minimise formation damage in development wells and formation damage mitigation is a key element in many field development plans. Historically attention has often been more focused on microscopic formation damage mechanisms and macroscopic production enhancement technology rather than on the effective management of the drilling and completion processes to mitigate skin. As a consequence, formation damage and its impact on well productivity in exploration and appraisal wells is often overlooked, so potentially economic and prolific fields have been condemned to be non-viable as a result of poor well productivity rather than poor permeability or connectivity. Formation damage during drilling and completion has led to poor test results and, especially in an environment where reservoirs are expected to be tight, the wrong conclusions have been drawn. An integrated re-evaluation of these assets coupled with at recognition of formation damage can unlock hidden reservoir potential. Byrne et al (2007) suggested that if one could understand clearly the degree and nature of any exploration or appraisal well damage then surely this would enable better understanding of all data produced. A dedicated formation damage study during the exploration and appraisal stage becomes a tool that can be used to aid decision-making later on in field life and potentially for the development of offset or analogue reservoirs. We are often faced with the question: is this a bad reservoir or is this a damaged well? The technology which enables this new interpretation is well established, but the application of the various techniques as an exploration tool is new. The methodology outlined and the processes described have many applications in suitable undeveloped discoveries.
Formation damage during drilling and completion has often led to poor well test results and, in many cases, the wrong conclusions have been drawn. Poor productivity has been mistaken for poor permeability and connectivity. Reservoir potential has been hidden and assets abandoned. However, the recognition of formation damage in unwanted assets has led to the re-evaluation of legacy drilling and production data. Two examples are presented which demonstrate the methodologies and techniques employed in an integrated solution for the recognition, diagnosis and mitigation of formation damage. In particular, return permeability tests on core in the laboratory are essential but must be coupled with a more rigorous validation of well test interpretations before reaching any decision on relinquishment or abandonment. An integrated petrophysical, geomechanical and formation evaluation strategy can open up significant development opportunities in what were regarded as uneconomic oil and gas fields. In one case, the methodology resulted in a ten-fold increase in absolute well flow potential and the commercial development of the field. The methodologies and workflows developed in these field examples mean that it is possible to drill and develop low permeability reservoirs economically without causing damage and avoiding the need for expensive stimulation through careful planning and design. Introduction Formation damage can be defined as any reduction in near wellbore permeability as a result of drilling, completion, production, injection, attempted stimulation or any other well intervention. The total cost to the industry in deferred production and remedial damage treatments is difficult to quantify. However if one were to extrapolate from the examples described in this paper, revenues worth billions of dollars are potentially overlooked due to poor characterisation of formation damage. Certainly, efforts continue to be made to minimise formation damage in development wells and formation damage mitigation is a key element in many field development plans. Historically attention has often been more focused on microscopic formation damage mechanisms and macroscopic production enhancement technology rather than on the effective management of the drilling and completion processes to mitigate skin. As a consequence, formation damage and its impact on well productivity in exploration and appraisal wells is often overlooked, so potentially economic and prolific fields have been condemned to be non-viable as a result of poor well productivity rather than poor permeability or connectivity. Formation damage during drilling and completion has led to poor test results and, especially in an environment where reservoirs are expected to be tight, the wrong conclusions have been drawn. An integrated re-evaluation of these assets coupled with at recognition of formation damage can unlock hidden reservoir potential. Byrne et al (2007) suggested that if one could understand clearly the degree and nature of any exploration or appraisal well damage then surely this would enable better understanding of all data produced. A dedicated formation damage study during the exploration and appraisal stage becomes a tool that can be used to aid decision-making later on in field life and potentially for the development of offset or analogue reservoirs. We are often faced with the question: is this a bad reservoir or is this a damaged well? The technology which enables this new interpretation is well established, but the application of the various techniques as an exploration tool is new. The methodology outlined and the processes described have many applications in suitable undeveloped discoveries.
This paper describes the application of dual lateral, level 4 junction - technology to successfully develop a marginal field in the Carboniferous area of the Southern North Sea (SNS) on the United Kingdom Continental Shelf (UKCS). This is the first known use of this technology in this area of the SNS where significant drilling risks have previously led to relatively simple well designs to mitigate the risk of failure. The Rita Field straddles blocks 44/21b and 44/22c and lies 110km due east of the United Kingdom coastline and 35km west of the UK-Dutch offshore boundary. The field is composed of adjacent, tilted, Carboniferous fault block structures containing Westphalian reservoir sandstones sealed by Silverpit shale and halites at the regional Base Permian Unconformity. The NW-trending fault blocks are separated by a NE - striking normal fault. The eastern fault block was successfully tested by 44/22c-9 in 1996 whilst the western fault block was targeted by 44/21b-11 in 1998 but failed to find gas. Well results, however, indicated the likely presence of up-dip reservoir quality Westphalian sandstones, although the development risk was higher. The selected development scenario was a dual lateral well from a single subsea wellhead, accessing both Rita main fault blocks. Although this concept yielded the most attractive economic development scenario, it nevertheless set the multidiscipline team with many significant well design challenges, including the following: Directional planning to target a gap within the high pressure Plattendolomite rafting in the Zechstein evaporite sequence whilst accommodating the reservoir strict targeting objectives of each leg. Utilising the five separate liner hanger systems that would be required in this single dual lateral well. Conducting extensive directional drilling within the Silverpit evaporite sequence with low weight OBM drilling fluid. Horizontal drilling up to 3000 ft of Carboniferous reservoir in 6 in hole whilst managing directional, hole stability and formation damage objectives. Placing the junction within a very confining area of the Zechstein basal sequence and achieving full cement isolation. Deploying the long 4 in. sandscreen lower completions. Mitigating the risk of formation damage in the first isolated reservoir leg whilst the second leg was being drilled and completed. Developing and deploying the first HPHT gauge through a 13-5/8 in vertical subsea tree in the UKCS. Further, as the western fault block was seen as an exploration target, the well design had to accommodate the geological uncertainly due to the poor quality of the seismic data, of the NE - striking normal fault and the planned reservoir entry point being out of position. Successfully dealing with these engineering challenges resulted in several industry firsts which will be fully described within the text of the paper. On completion, production rates were better than expected with very good selective delivery from both legs of the well prior to co-mingling.
Drilling overpressured and deep reservoirs is a challenge in itself, but can be complicated by the need to drill through depleted (depressurized) shallower reservoirs. The field under study consists of multiple stacked clastic reservoirs bounded by steeply dipping sealing faults. The deeper reservoirs fall in the high pressure high temperature (HPHT) category and account for one third of the in-place volumes. Ideally, field development for such stacked reservoirs is recommended through the "bottom-up" strategy to prevent late-in-life drilling through depleted zones with reduced drilling window and increased risk of fluid losses and well failure. Here, this would imply drilling and developing the deeper HPHT reservoirs before the shallow, normally pressured reservoirs. From a technical and financial perspective, it is tempting to develop and produce the shallow, normally pressured reservoirs (that contain 70% of the volumes and also have better flow properties) first, and bring the deeper HPHT reservoirs on-stream later. But, is such phased development of the reservoirs possible? Or would producing from the shallower reservoirs first permanently damage our ability to drill and produce the deeper HPHT reservoirs at a later stage in field life? These were the questions we tried to answer in this work. We built a full-field finite element model to simulate the geomechanical response of the reservoirs to pressure depletion i.e. quantify the displacement, strains and total stress changes in and around the reservoirs as a function of production. Such geomechanical models can serve as a predictive tool to help answer the questions above. In this paper, we show the construction and application of such a geomechanical model in field development planning. Our paper highlights how our geomechanical model results were applied, together with other work, to develop this field safely and efficiently, emphasizing field life cycle value.
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