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Collaborating Authors
North Sea
Abstract In many oilfields the relatively small number of high-cost, highly productive wells, coupled with a carbonate and or sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery. The nature of the well completion strategy in new fields such as frac packs for sand control and acid stimulation for carbonate reservoirs had resulted in some wells with higher than expected skin values due to drilling fluid losses, residual frac gel, fluid loss agents, and fines mobilization within the frac packs where applied. The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale inhibitor packages to sandstone and carbonate reservoirs. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (<20ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments for both sandstone and an HP/HT gas condensate carbonate reservoir. The lessons learned fromcarbonate corefloodevaluationunder HT/HP conditions when appling stimulation fluids with and without scale inhibitor present in the treatment stageswill be presented. Many similar fields are currently being developed in offshore Brazil, West Africa and Middle East, and this paper is a good example of best-practice sharing from another oil basin.
- Asia > Middle East (0.69)
- Africa (0.68)
- Europe > United Kingdom > North Sea > Central North Sea (0.28)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Alba Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Fladen Ground Spur > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- (4 more...)
An Occidental rig working in the Permian Basin of west Texas and New Mexico, an area of high activity for the company in mature field operations. Revitalizing these fields extends their The term mature field does not have a single definition. Individual A 2011 report, "Mature Oil Fields--Unleashing the companies may apply their own definitions. Potential," by IHS Cambridge Energy Research Associates, "We consider the subsurface and the surface," indicated that approximately two-thirds of global daily said Olivier Heugas, a member of the mature field team at average oil production comes from mature fields and that the Total's headquarters near Paris. "For the subsurface, we percentage is increasing over time. Regardless of the definition, mature fields are a huge global resource. With reserves categorized as proved or probable, attempts to expand reserve levels come at a relatively low risk. Modest additions to a base of this size can be very substantial. Revitalizing a mature field means taking measures that increase the value extracted from the field beyond original expectation. Every field has a production curve over which production grows to a peak level and then declines until it reaches the point at which operation is no longer economic. Revitalization extends the natural decline curve to increase ultimate economic hydrocarbon production. A variety of measures may be used, including the application of additional technology to characterize, monitor, and manage the producing reservoir; improve drilling and completions; and boost the recovery factor. Achieving significant cost reduction in field operations, through technology application or more effective work processes and business practices, can also play an important role. Although the aim of revitalization is to boost future production and recovery levels, it is crucial that an operator has first taken the steps to assure that original producible reserves goals are being met. Heugas explained Total's approach to revitalizing mature fields. "First, we must secure what we plan to produce from existing facilities, which are aging," he said. "And for that, we need to implement our development plans effectively for programs such as infill drilling and invest in maintenance.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (61 more...)
Summary Several multirate separator tests (MRTs) have been undertaken on wells in the Veslefrikk field that are on commingled production from the Brent Group and Intra Dunlin Sand (IDS). During these tests, produced-water (PW) samples were also collected. Integrated analysis of the results of interpretion of the PW analyses and the MRT results has provided a range of information for each production zone, including the nature and composition of the PW, the seawater fraction of these produced waters, the fraction of total water flow being produced, pressure, productivity index, oil and water rates, and water cut. This information can reduce the need for running production-logging tools (PLTs), allows the scaling potential between the deeper and the shallower zones to be evaluated, aids squeeze-treatment design, is beneficial for predicting formation damage from crossflow, and aids water-shutoff decisions. In an accompanying paper, McCartney et al. (2012) describe how PW analyses from the MRT are interpreted to determine— among other parameters—the amount of water produced from each zone (water allocation) at each of the test rates during an MRT. In this paper, the methods of analyzing these results in combination with separator-test data are described with the aid of a field example to demonstrate how they provide detailed information about the downhole conditions and zone properties of the well. On the basis of the analysis, a set of well interventions was recommended. Following confirmation of the principal MRT results by a PLT, some of the recommended interventions have been performed successfully. Experience from Veslefrikk suggests that MRTs can be considered as a possible replacement for running PLTs or as an additional source of data that can be acquired more frequently.
- North America > United States (0.67)
- Europe > Norway > North Sea > Northern North Sea (0.35)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > NOAKA Project > Krafla North Prospect > Etive Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 30/6 > Veslefrikk Field > Statfjord Group Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 30/6 > Veslefrikk Field > Dunlin Group Formation (0.99)
- (14 more...)
Abstract In a deepwater West African field the relatively small number of high-cost, highly productive wells, coupled with a high barium sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery. The nature of the well completion strategy in the field (frac packs for sand control) had resulted in some wells with higher than expected skin values due to drilling fluid losses, residual frac gel, fluid loss agents, and fines mobilization within the frac packs. The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale inhibitor packages to deep water wells. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (>20ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides a cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments. The five field treatments that were performed demonstrate how these coupled applications have proven very effective at both well stimulation/skin reduction and scale inhibitor placement prior to and after seawater breakthrough. The term "squimulation" is used by the local operations team to describe this simultaneous squeeze and stimulation process. Many similar fields are currently being developed in the Campos basin, Gulf of Mexico, and West Africa, and this paper is a good example of best-practice sharing from another oil basin.
- Africa (1.00)
- Europe > United Kingdom > North Sea (0.28)
- North America > United States > Texas (0.28)
- Geology > Mineral > Silicate (0.94)
- Geology > Geological Subdiscipline (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.68)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment (0.46)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > East Texas Salt Basin > Alba Field (0.99)
- Europe > United Kingdom > North Sea > North Sea Basin (0.99)
- Europe > Norway > North Sea > North Sea Basin (0.99)
- (5 more...)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE International Conference and Exhibition on Oilfield Scale held in Aberdeen, UK, 30-31 May 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Economical field development strategy often implies tie-in of subsea satellite fields to nearby host installations. This leads to a whole new set of benefits and challenges considering design and material selection, production volumes and limitations, company strategies, holistic management and multi-disciplinary approaches. Operation of complex systems with multiple fluid streams demands a broader understanding of the chemical processes taking place when different fluids are mixed. Typical challenges include mineral scale and "soft scale" deposits. To ensure optimum production and provide flow assurance through chemical management, proper monitoring is essential. Guidelines and best practices are even more required if the tie-in to the host includes several operators and service companies. Over the years, the Statoil operated Oseberg asset has through close cooperation with its chemical supplier M-I SWACO systematically improved the sampling and analysis procedures to strengthen the quality of data used in system monitoring. The supplier needs to have a strong focus on flow assurance related to chemical management and provide a range of onshore and offshore monitoring techniques and tools. Challenges from the North Sea Oseberg Field Centre installation with subsea tie-ins have been discussed. Laboratory and field data from bottle tests, chemical analysis, preservation techniques and scaling potential simulations are presented. The results have been used to plan for side stream tests, develop guidelines for early identification of flow assurance challenges, sampling and monitoring of complex fluid systems and chemical management to avoid process upsets and production losses.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.46)
- Europe > Norway > North Sea > Northern North Sea > Statfjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 190 > Block 30/8 > Tune Field > Brent Group > Tarbert Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 190 > Block 30/8 > Tune Field > Amundsen Formation > Tarbert Formation (0.99)
- (74 more...)
Abstract In many oilfields the relatively small number of high-cost, highly productive wells, coupled with a carbonate and or sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery. The nature of the well completion strategy in new fields such as frac packs for sand control and acid stimulation for carbonate reservoirs had resulted in some wells with higher than expected skin values due to drilling fluid losses, residual frac gel, fluid loss agents, and fines mobilization within the frac packs where applied. The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale inhibitor packages to sandstone and carbonate reservoirs. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (>20ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments for both sandstone and carbonate reservoirs. The four field treatments that were performed demonstrate how these coupled applications have proven very effective at both well stimulation/skin reduction and scale inhibitor placement prior to and after seawater breakthrough in a sandstone reservoir. The lessons learned for the evaluation of the carbonate core via coreflood studies will also be presented. Many similar fields are currently being developed in the Campos basin, Gulf of Mexico, West Africa and Middle East, and this paper is a good example of best-practice sharing from another oil basin.
- Europe (1.00)
- North America > United States (0.88)
- Africa (0.86)
- Asia > Middle East (0.69)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Brazil > Campos Basin (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Alba Sandstone Formation (0.99)
- (2 more...)
Copyright 2012, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 30 April-3 May 2012. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright. Abstract With the present deepwater developments on the increase it is foreseen that a dedicated market will develop for vessels capable of intervening on subsea wells at a lesser cost than existing deepwater drilling units. Thereby (I) extend the life of deepwater developments rendering additional profits and (II) adhere to minimum field production requirements as are being required by the authorities more and more to date. The paper describes the development of the concept for such a Well Intervention Vessel resulting from a combined effort between a Naval Architecture Design Bureau and a major rig equipment supplier with a focus on an open equipment structure facilitating the possible application of multiple levels of/and intervention solutions. The vessel will target Class B /(II) and Class C/(III) type interventions, based upon systems which will use risers and capable of retrieving completions.
- Europe > United Kingdom > North Sea (0.89)
- Europe > Norway > North Sea (0.89)
- Europe > Netherlands > North Sea (0.89)
- (3 more...)
Pushing the Boundaries of Concentric-Coiled-Tubing Technology To Resurrect Subhydrostatic Gas Wells on an Unmanned Offshore Installation
Davies, Ann (BP Exploration Company) | Dunning, Matthew (BP Exploration Company) | Kuchel, Mike (Baker Hughes) | Roberts, Tony (Baker Hughes) | Taggart, Michael (Baker Hughes)
Summary Ravenspurn North is a mature gas field in the southern North Sea with 42 wells, drilled (and many hydraulically fractured) in the late 1980s. By 2006, more than half of the wells had ceased to flow, and many were flowing intermittently. With ailing wells and consequently falling production rates, the longer-term future for Ravenspurn North field was uncertain. A wireline campaign suggested a common failure mode for many wells: Large amounts of proppant had accumulated in the wellbore. Modeling of the potential range of static and dynamic pressure losses caused by this proppant supported a significant enhancement to the remaining gas potential. However, the depths of the wells combined with subhydrostatic pressure conditions and large-diameter lower completions made achieving cleanout challenging. Furthermore, the target wells were located on unmanned offshore installations with minimal facilities, deck space, and deck loading. This paper details how each of these obstacles was successfully tackled to reinstate a target set of wells. It describes the various cleanout options that were considered, and why concentric-coiled-tubing vacuum technology (CCTVT) was ultimately selected. Before this project, CCTVT had never been deployed in the North Sea, and nowhere in the world at these reservoir depths. The operation was delivered on the small unmanned installation by conducting the world's first boat-spooling operation of concentric coiled tubing (CCT); rigorously reassessing deck loadings; and running the operation completely self-sufficiently, with a maximum of 10 personnel onboard. Finally, this paper provides a detailed description of the successful CCTVT operations that recovered a total of 2,950 lbm of proppant from three wells to expose the perforations and unload the wells of liquid. Furthermore, CCT was used to mill out tubing-profile nipples and install a packer to hang off 1,200 ft of flush-joint tail pipe. Innovative thinking and close collaboration between operator and service companies were required, because the ability to perform multiple operations on CCT was in itself pioneering. Overall, this campaign has pushed the boundaries of intervention technology to deliver an extremely challenging project. This has resulted in a more-certain future for the Ravenspurn North field, as well as newly unlocked opportunities in deep depleted gas wells worldwide.
- North America > United States (0.94)
- Europe > United Kingdom > North Sea > Southern North Sea (0.45)
- Asia > Middle East > Qatar > Arabian Gulf (0.45)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > P 033 > Rotliegendes Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 43/26a > Ravenspurn North Field > Rotliegend Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 42/30 > Ravenspurn North Field > Rotliegend Formation (0.99)
- (2 more...)
Abstract In a deepwater West African field the relatively small number of high-cost, highly productive wells, coupled with a high barium sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery. The nature of the well completion strategy in the field (frac packs for sand control) had resulted in some wells with higher than expected skin values due to drilling fluid losses, residual frac gel, fluid loss agents, and fines mobilization within the frac packs. The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale inhibitor packages to deep water wells. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (>20ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides a cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments. The four field treatments that were performed demonstrate how these coupled applications have proven very effective at both well stimulation/skin reduction and scale inhibitor placement prior to and after seawater breakthrough. The term "squimulation" is used by the local operations team to describe this simultaneous squeeze and stimulation process. Many similar fields are currently being developed in the Campos basin, Gulf of Mexico, and West Africa, and this paper is a good example of best-practice sharing from another oil basin.
- Africa (1.00)
- North America > United States > Louisiana (0.28)
- Europe > United Kingdom > North Sea (0.28)
- North America > United States > Texas (0.28)
- Geology > Mineral > Silicate (0.94)
- Geology > Geological Subdiscipline (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.68)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment (0.46)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > East Texas Salt Basin > Alba Field (0.99)
- Europe > United Kingdom > North Sea > North Sea Basin (0.99)
- Europe > Norway > North Sea > North Sea Basin (0.99)
- (5 more...)