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Abstract A Brown field has been in production for over 30 years. A redevelopment plan started in 2004 to revamp oil production under an Alliance partnership between an Oil & Gas Company Malaysia and Schlumberger. The mentioned Brown field is a multilayered reservoir where the UCS can vary from 1500 psi in the consolidated sand until less than 800 psi in the shallow zones. Based on a geomechics study and existing production history of the field, unconsolidated producer sands were identified and sand control methods were evaluated according to the degree of achieving the goals, and reducing risk, the result indicates that the Cased Hole Gravel Pack with Alternate Path System was preferential. Additional information was obtained in the latest campaign during the retrieval of gravel pack screens in 2 sand producing wells, which gave a better understanding of the failure mechanism in the previous gravel pack operations. The main changes in the design of sand control systems during 8 years includes adopting a perforating strategy of performing a mechanical backsurge, increasing shot density and charges with low debris, use of a 3-way sub tailpipe system to avoid problems associated with breaking flapper valves and debris accumulation, number of cup packers, size of screens, slurry concentration and back pressure applied during the treatment. Furthermore the evolution in the sand control management have showed benefits such as increasing the number of gravel pack zones per well, performing longer gravel packs, installing permanent downhole gauges and using bigger tubing. This paper presents as case study of the evolution and the impact of the sand management systems, showing the significant changes in the design and execution of gravel packs and describing the reasons for those changes. The impact is analyzed on the basis of formation damage, GP factor, execution, risks and results of the initial production.
- Asia (1.00)
- North America > United States > Texas (0.95)
Abstract The Captain Field which lies off the coast of Scotland is a shallow sandstone reservoir (3000 ft) comprising clean, unconsolidated sand with high permeability (up to 5D). The oil is heavy and bottomhole temperature very low (30 C). Throughout the development of this field (14 years) two of the main challenges have been control of unconsolidated sand and maximising production of the oil by water injection to maintain reservoir pressure. Particular attention has been paid to drilling and completion of the water injection wells. The drill-in fluid used was initially oil based mud but changing to water based drill-in fluid facilitated use of faster completion procedures. Initially, when using a water based drill-in fluid, displacement of the openhole to clear brine was always troublesome. This issue was resolved by the introduction of a new low temperature starch into the drilling operation. Adoption of the new formulation has facilitated a simpler, faster displacement operation and made it easier to test various techniques that are offered for filtercake clean up. Treatments, involving acetic acid released in situ, enzymes, sequestering agents, etc., provided questionable results. However, a breaker system that provides a delayed release of formic acid has recently been introduced and has led to a significant improvement in performance. New techniques have introduced significant benefits, for example: the improved starch shortened the completion process by at least several hours of rig time, the four most recently completed wells which were all treated with the formic acid system had an average initial Specific Injectivity Index that was about 50% better than the average achieved for the first five wells that were completed with oil based mud. The paper will present important aspects of the learning process on the Captain Field with particular emphasis on application of the new starch, and drilling/clean-up of the water injection wells.
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/29a > Ross Field > Ross Formation (0.98)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/29a > Ross Field > Parry Formation (0.98)
- (3 more...)
Abstract High-rate water-pack (HRWP) completions frequently perform poorly in both hydrocarbon productivity and production endurance. This poor performance has been linked to pack-permeability damage caused by the fines invading the pack and migrating toward the wellbore. The NanHai West Bay reservoir is a sandstone formation with high C02 content. It exhibits moderate to high permeability and a high sanding tendency caused by weakly consolidated formation and high watercut. To access this reservoir, multiple wells from two separated platforms were completed in 2002 with HRWPs and extension packs (EPs). The EP completions used proppant that was coated with a surface-modification agent (SMA). This completion method was selected to bypass the near-wellbore damaged formation by creating wide and short propped fractures without fracturing into the nearby water zone. Completion tools consisted of 13Cr material because of high CO2 concentrations. A short and compact weight down-tool system was chosen so that the wells could be completed efficiently with limited rig space on unmanned platforms. This paper presents the long-term evaluation results of these wells and provides detailed descriptions of the completion procedures, challenges, and the difficulties during the course of these treatments. Field results of these HRWP- and EP-treated wells show that their productivity continues to hold up at levels better than expected, even after more than seven years of production. These wells continue to produce at low drawdowns without causing mechanical damage to the proppant packs and sand-control screens, despite the high sanding tendency, high watercut in the formations, and frequent exposure to stress cycling as the wells undergo production and shut-in.
- North America > United States (0.94)
- Asia > China > South China Sea (0.28)
- Asia > China > South China Sea > Zhujiangkou Basin (0.99)
- Asia > China > South China Sea > Pearl River Mouth Basin > Wenchang Field (0.98)
- Well Completion > Sand Control (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract When a Gravel Pack Completion fails it usually results in the loss of production from the interval until a workover rig is available to re-complete the well. This paper describes two recent successful rigless interventions completed in offshore multi zone completed gas wells in the Adriatic Sea. A key factor in the successes of these remedial treatments has been application of two different chemical technologies applied to the proppant whilst it is being pumped into the well. In the first well, production loss was caused by fines migration (fine silt = 44 micron) into the 40/60 gravel pack sand, which completely plugged the screens and gravel. An intervention was performed which included sealing the existing completion, followed by re-perforating the premium screen using wire line guns. The interval was then fractured with a tip screen out design and a thru tubing screen was placed across the perforated screen. Critical to this treatment was the use of a surface modifying agent to prevent fines migration and plugging of the gravel pack. Production results have confirmed the correctness of the technical choice. A different problem existed on the second well, which had a fracpac completion; in this case a screen failure resulted in formation sand and proppant being produced to the surface. The well was re-fractured through the hole in the screen and a newly developed resin was applied to the proppant to lock the proppant into place and thus repair the damaged screen without restricting the flow area with a secondary inner string. Unlike conventional resin coated proppant at low temperatures this new type of resin does not require confinement pressure and or the use of chemical flushes to cause the resin to set. Since the intervention, the well has been producing sand free at very close to the original PI. In both cases these treatments have put back in production wells that in the past the only alternative was to recomplete using a workover rig. This paper will describe the treatment design, well operations performed, materials used and production performance of each well comparing this to a conventional recompleted well. Overview of Sand Control Work in the Adriatic Background Sand control has been necessary in the Adriatic gas fields since the first wells were placed in production, initially the best option was conventional low density gravel pack in the open hole (OHGP). With the pressure depletion and as the reservoirs drilled became more complex, cased hole completions became necessary for isolation between the main layers to prevent water production and enable layers to be fully depleted. Cased hole completions being typically multilayer completions and dual strings with 3 to 5 or even more individual intervals completed per well. Reservoir lithology comprises of alluvial sands, turbiditic deposits that were laid down by the Po river in the Pliocene era. The depths of the gas fields vary from 800 mTVD to over 3500 mTVD. These sands are almost clay like in nature and are highly plastic interbedded with stronger shale bands separating the main layers. Interval height varies from 2 m up to 30 m, with permeability ranging between 5 to 500 md to gas. Pore gradients also vary widely from over pressurized sand with pore pressure of 1.6 sg to partially depleted structures with pore pressures of as low as 0.2 sg. As the main area of the original fields have become increasing depleted the current new completions are sidetracked from the pre-existing platform wells into smaller less depleted sand lenses. These structures are increasing siltier and of lower quality sands. In most parts of the world this type of formation would not be considered for commercial extraction of the gas resource.
- Europe (1.00)
- North America > United States > Texas (0.67)
- North America > United States > Louisiana (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.34)
- North America > United States > Texas > Fort Worth Basin > Barbara Field (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
Abstract Chirag field was the first of three fields put into production in the Azeri - Chirag - Guneshli (ACG) megastructure, located in the Azeri sector of the Caspian Sea and operated by BP on behalf of Azerbaijan International Operating Company (AIOC). Production commenced in late 1997 after completion of the Chirag A01T1 well. A number of different sandface completion types have been installed in Chirag injectors and producers during the Chirag Early Oil Project (EOP), and significant data have been collected to evaluate the performance of each completion type. Completion types include cased and perforated, open hole gravel packs (OHGP) using wire-wrapped, pre-packed and alternate path (shunt-tube) screen technology, stand-alone porous metal fiber premium screens, and expandable screens. To date, 29 completions have been installed in 19 of 24 available well slots in primary and sidetrack wells. Many of the producing wells are equipped with permanent downhole pressure-temperature gauges, the flowlines are equipped with acoustic sand detection devices, and an active separator production test and surveillance program has resulted in a quality data set to evaluate completion performance under initial "dry oil" (water free) conditions, and upon the onset of produced water. This quality data set has greatly assisted the completions performance analysis, which has helped shape completion decisions and technology requirements for full field development. The paper will review the completion evolution in Chirag field, the relative performance of completion types over a broad range of indicators, and will include a discussion about measures taken to improve open-hole gravel pack performance from a reservoir damage perspective, with a focus on producers. Introduction A large majority of recently discovered fields are in sandstone formations that require some form of sand management technique, varying from selective and/or oriented perforating to open hole gravel packing. For example, approximately 50% of BP's hydrocarbon production will come from unconsolidated sandstone formations within the next 5 years. Selection of the most suitable sand management technique for such reservoirs is challenging, often requiring substantial amount of data at a significant cost. Even then, tectonic events and other uncertainties may result in failure of sand management techniques that appeared to be suitable based on all available data, making experience in the area the most valuable resource for future completions. Sand management techniques include oriented and/or selective perforating,[1] formation consolidation,[2] stand alone screens,[3] expandable screens,[4] fracturing for sand control,[5] cased-hole gravel-packing[6] or frac-packing,[7] open-hole gravel-packing[8] or frac-packing,[9] or some combination of these methods.[10] These techniques have been applied in other basins based on a variety of drivers for a given project and with varying degrees of success. One of the most important considerations in selection of a completion technique is the cost of remediation. This can drive operators towards completion types that will provide the maximum reliability for sand control throughout the anticipated well life - without a significant reduction in productivity. For example, a cased and perforated completion without any screens can yield the lowest possible skin, although subsequent sand fill in the wellbore may necessitate periodic cleanouts or continuous and excessive sand production may result in restricted flow rates for sand-free production. The resulting remediation and/or restricted flow erodes the economic value of the well. On the other hand, a cased or open-hole gravel pack may either eliminate or minimize solids production, albeit with a higher, nevertheless acceptable, skin.
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/30 > Scoter Field (0.99)
- Asia > Azerbaijan > Caspian Sea > Apsheron-Pribalkhan Ridge > South Caspian Basin > Azeri-Chirag-Guneshli Field > Chirag Field (0.99)
- Africa > Angola > South Atlantic Ocean > Lower Congo Basin > Block 17 > Girassol Field (0.99)
- (8 more...)
Rock Mechanics Aspects of Well Productivity in Marginal Sandstone Reservoirs: Problems, Analysis Methods, and Remedial Actions
Tronvoll, Johan (SINTEF Petroleum Research) | Larsen, Idar (SINTEF Petroleum Research) | Li, Liming (SINTEF Petroleum Research) | Skjetne, Tore (SINTEF Petroleum Research) | Gustavsen, Øyvind (SINTEF Petroleum Research)
Abstract The paper discusses different mechanisms that may explain field observations of productivity decline. In particular, this work reviews some central issues related to rock mechanical processes that may directly or indirectly result in productivity decline and also possible remediation in sandstone reservoirs. Some emphasis is put on particle plugging of the formation itself, screens and gravel packs, scaling in the near-wellbore region, behind the screen/gravel sand production (including quantification of produced sand volume/damaged zone), filtercake mobilization, near-wellbore rock compaction and effects of water breakthrough on rock properties. All these mechanisms are directly or indirectly linked to rock mechanics aspects through local pore pressure changes and induced deformations of the formation rock. Plugging may further induce rock mechanical failure around the well. Two principles of direct sand control are discussed, i.e. borehole re-enforcement (expandable screens, gravel-packing, propped fracturing, chemical consolidation) and filtering (standalone screens, gravel-packs, frac-packs, pre-packed screens) and their impact on productivity upon reservoir depletion, scaling, sand production, filtercake mobilization and fines migration. Different analyses are used to highlight central mechanisms of productivity alteration and to define design parameters. In particular, chemo-mechanical effects upon water breakthrough are discussed with respect to permeability alteration around the wellbore and scale formation. Further, examples will be given that remedial actions to remove scale and other plugging agents in certain cases may harm the formation mechanical integrity, and result in sand production, rock compaction and productivity decline. An example of a simple laboratory test to quantify such loss of rock integrity will be given. The work demonstrates how rock mechanical analysis may guide the selection of completion method, and how proper diagnosis of well performance and formation integrity may guide the selection and design of remedial actions. Introduction The productivity of oil and gas wells is used as a measure of the success of the drilling and completion of the well. Productivity as defined in a classical well test, relates the produced hydrocarbon rate to the production pressure drop (drawdown). However, in economical analysis, where cash-flow is central, the production rate itself, i.e. produced hydrocarbon volume per time unit, is still the central parameter. Though, the more technical productivity measure is merely an aid to understand well behavior and the effect of various completion and stimulation measures. Moreover, from a reservoir management perspective, productivity is not restricted to well behavior alone, but it is also related to the energy in the entire reservoir (i.e. the pressure evolution and the relative movements of fluids in the reservoir). Sand production is one classical productivity restriction in economical means, as sand production has historically led to the choking back of the well and thus reduced cash flow. More recent sand management practices have, however, shown very good results in both technical and economical terms through controlled sand production to surface rather than classical ‘sand control’ through total sand exclusion [1. 2. 3.]. Recent sand management practices has thus challenged the classical sand control philosophy and led to higher industry demands in terms of cost of installation and resulting productivity. In our study, we have focused on direct and indirect rock mechanical aspects of well productivity, and we have neglected reservoir scale effects, such as compaction and water/gas coning, as well as wellbore flow effects. In doing so, we have slimmed down the analysis to processes at the wellbore wall and its immediate vicinity. This is motivated by the high impact on productivity of changes in sand face geometry and formation properties in the near-wellbore zone. Also, most man-made impacts are related to well operations in the widest sense.
- Europe (0.70)
- North America > United States > Texas > Dallas County (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Well Drilling > Wellbore Design > Rock properties (1.00)
- Well Completion > Sand Control > Screen selection (1.00)
- Well Completion > Sand Control > Gravel pack design & evaluation (1.00)
- (3 more...)
Abstract A large majority of the wells in deep-water/subsea environments are being drilled as horizontal wells to gain cost-effective accessibility to multiple sand bodies and larger reserves. Most of these wells are being completed as open holes because of the higher productivities as well as lower costs associated with such completions. Furthermore, a substantial fraction of the fields in deep-water environments requires some sort of sand control. Although standalone screen completions have been used successfully in some of these deep-water fields (relatively large sand grains and uniform particle size distributions, with little to no fines), premature sanding problems have been reported, jeopardising project economics as a result of prohibitively high cost of remediation. In this paper, we present a significant case history on the application of the simultaneous gravel-packing and cake-cleanup technique in the Foinaven field, West of Shetland, UKCS. The well is the first gravel-pack completion in this deep-water, harsh environment, where various types of standalone screen completions have been utilised since the initial development of the field in 1994. The subject well is of 3,075-ft open hole, penetrating through two sand bodies separated by a 530-ft shale section. It is the first openhole gravel-pack completion in such an environment in the North Sea to result in 100% packing efficiency based on gauge hole calculations and a zero mechanical skin based on pressure build-up testing. In addition to being the first horizontal well West of Shetland to be drilled with water-based mud (WBM), this was the first production well to be drilled in a new reservoir horizon of the field, discovered and brought on line in less than 10 months. Initial production from the well far exceeded expectations and the completion was delivered safely and 3 days ahead of the target time. Introduction It is widely recognized in the industry that properly selected reservoir drilling fluids along with properly designed filter-cake removal treatments are essential to achieve high-productivity wells with low skin, particularly in gravel-packed completions where the filtercake is trapped between the gravel-pack and formation. Engineering the filtercake cleanup to be incorporated into the gravel-pack carrier fluid provides a cost-effective and uniform filtercake removal along long horizontal openholes, eliminating remedial treatments. However, this approach requires significant integration of different disciplines of well construction and completion. Previous publications have elaborated on reservoir drilling fluid selection for optimisation of the cleanup process, and the integration of custom engineered solutions. Based on friction pressures derived during yard testing, shunt tube technology for openhole gravel packs can successfully pack long openhole sections in excess of 5,000 ft pumping at low rates (e.g., 2.5 bbl/min). At these rates there is a requirement for the carrier fluid to exhibit superior rheological properties to avoid the gravel from settling out when pumping down a large-diameter workstring. In the severe conditions West of Shetland, this was a significant extension to the technology's proven limits in a harsh deep-water subsea environment. Critical to the success of any shunt-tube gravel-packing operation is the rheology of the carrier fluid; it must meet the minimum requirement for slurry transportation in the shunt tubes.
- North America > United States (1.00)
- Europe > United Kingdom > Atlantic Margin > West of Shetland (0.54)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Viosca Knoll > Block 915 > Marlin Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/24a > Foinaven Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/19 > Foinaven Field (0.99)
- Well Drilling (1.00)
- Well Completion > Sand Control > Gravel pack design & evaluation (1.00)
Alternate Path Completions: A Critical Review and Lessons Learned From Case Histories With Recommended Practices for Deepwater Applications
Hurst, G. (Schlumberger) | Cooper, S.D. (BP) | Norman, W.D (ChevronTexaco) | Dickerson, R.C. (ChevronTexaco) | Claiborne, E.B. (Amerada Hess) | Parlar, M. (Schlumberger) | Tocalino, S. (Schlumberger)
Abstract Since its introduction, over 700 alternate path sand control completions have been implemented around the world ranging from single zone cased hole gravel-packs to multi-zone fracpacks and fibre optic (DTS) enabled open hole horizontal completions. Over the last six years, the alternate path system has been field proven to provide high reliability in achieving complete packs as well as additional features allowing simultaneous cake cleanup, shale bypass and other contingencies that enable doing it right the first time in deep-water/subsea completions where interventions tend to be economically and logistically prohibitive. This paper provides a critical review of those completions, capturing both successes and failures, along with the lessons learned in their design, execution and evaluation in relation to completion efficiency in sanding reservoirs. Furthermore, it details future development work and enablers that will allow the use of alternate path technology as the mainstay of intelligent well solutions, geometrical design improvements to provide optimal aspect ratios in the wellbore and its applicability in conjunction with water packing. Introduction Alternate Path is a technique that was developed to bypass any annular blocking that may occur during the completion process due to various reasons. Its original design consisted of steel rectangular tubes (also called shunt tubes) welded on screens, where the tubes had holes for exit of the slurry out of the tubes and into the annulus once the blocked annular section is bypassed. This original design was intended primarily for use in cased-hole gravel packs. As such, this design (tubes with relatively small flow area and with holes drilled on) was sufficient for the pump rates, slurry volumes and the interval lengths that are commonly encountered in those applications. During the last six years, various improvements were made to the original design to address the specific needs for a variety of applications as discussed in the next section. Although the initial applications of the alternate path technique have been directed towards improvement of gravel placement in cased holes, its current applications in fracpacking and open-hole horizontal gravel packing significantly outnumber cased hole gravel pack applications, in line with higher popularity of frac-packs and open hole gravel packs as reliable sand control techniques that yield high-productivities, particularly in deep-water/subsea environments. Thus, the review will focus primarily on alternate path case histories in these two areas, although examples of cased hole gravel packs will also be included for completeness. The paper is organized as follows. First, we summarize the evolution of the alternate path system, highlighting the reasons for each improvement along with the benefits and potential disadvantages or limitations. We then continue with a discussion of the cased-hole followed by open-hole applications of the alternate path, providing some statistical information, along with a brief review of representative case histories as well as lessons learned for each application and some key considerations to ensure successful applications in the future. This is followed by a summary of further improvements that are currently being worked on. Finally we draw conclusions.
- Europe (0.94)
- North America > United States > Louisiana (0.47)
- South America > Venezuela > Anzoátegui > Eastern Venezuela Basin > Maturin Basin > Carabobo Blocks > Dacion Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Ship Shoal South Addition > Block 359 > Mahogany Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Ship Shoal South Addition > Block 349 > Mahogany Field (0.99)
- Europe > Norway > Norwegian Sea > Åre Formation (0.99)