Swell Packers Research Articles

Study Reviews Multilateral Installation Improvements on the North West Shelf

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32910,“A Decade of Multilateral Technology Installation Improvements Down Under,” by Stefano Cappiello and Adam Pasicznyk, SPE, Halliburton. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. _ Multilaterals wells on the North West Shelf of Australia have been installed for over a decade. An overview of the well architecture, technology evolution, reliability, and efficiency of these operations is presented in the complete paper. The study is focused on subsea multilateral campaigns, where multiple global and regional first installations took place in mature fields. Introduction Multilateral developments in Australia mainly have been completed off subsea installations, with fewer performed from jack-up rigs. These multilateral completions mostly have been installed with the junction located in the producing reservoir sands. Technology Advancement of Multilaterals (TAML) Level 5 completions have successfully been deployed. The authors classify related systems as follows, with the most attention paid in the synopsis to the final two classes: - Generation One (Field A) - Generation Two (Field B) - Generation Three (Field C) - Generation Four (Field A) General Multilateral Well Design Because of sand production within the reservoir, these applications typically require a TAML Level 5 completion system. These systems deliver hydraulic and mechanical isolation at the junction through the completion. The junction is isolated above and below by production packers and by swell packers in the lateral. The junctions typically are installed horizontally within the reservoir. The original general requirements to construct Level 5 multilateral junctions included the following: - Ability to construct a Level 5 Junction in the 9⅝-in. casing or liner - Ability to run a landing profile or coupling as part of the 9⅝-in. production casing or liner - Ability to run and orient a premilled window at depth - Drill-out 8½-in. openhole section into the mainbore and into the lateral - Junction installed within the reservoir at high angle - Window milling to be performed in one trip - Lateral completion to be installed in one trip - Compressive strength rating capable of running screen sections over 2 km As the operators began to adopt multilateral technology in Australia, the following requirements were incrementally added: - Ability to deliver a Level 5 multilateral system in an existing well - Ability to deliver a trilateral well - Improve efficiency and reduce installation time

Approach Improves Vertical and Areal Sweep in Tengiz Platform Sour-Gas Injection

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203995, “Injection and Production Optimization for Tengiz Platform Sour-Gas Injection by Reactive and Proactive Conformance Completions Control,” by Shusei Tanaka, SPE, and Matthieu Rousset, SPE, Chevron, and Yousef Ghomian, SPE, Tengizchevoil, et al. The paper has not been peer reviewed. _ Sour-gas injection (SGI) operations have been implemented in the Tengiz field since 2008 and will be expanded in a future project. Because of limited gas-handling capacity, production at a high gas/oil ratio (GOR) has posed a challenge, resulting in potential well shutdowns. The objective of the study described in the complete paper was to establish an efficient optimization work flow to improve vertical and areal sweep, thereby maximizing recovery under operational constraints. This will be achieved through conformance-control completions that have been installed in many production and injection wells. Introduction The Tengiz field is in northwestern Kazakhstan on the northeast shore of the Caspian Sea. The reservoir extends 20 km2 with an oil column of approximately 1.6 km in a carbonate buildup structure at 3850 m subsea. Tengiz produced oil has a specific gravity of 47 °API with approximately 13% of hydrogen sulfide (H2S) and 3% CO2 in produced gas. At initial reservoir conditions, the GOR was 2,242 scf/STB and oil viscosity was 0.22 cp. At the time of writing, the production strategy follows gas-injection processes in the central to north platform area while depletion drive exists at the platform margin to the slope, where fractures appear to dominate flow dynamics. The production area is maintained above saturation pressure based on surveillance data for both the platform and slope zones. Tengiz SGI With Vertical Conformance Control The authors write that 20% of produced gas at Tengiz field is reinjected into the central platform area, which consists of the Bashkirian (Bash), Serpukhovian (Serp), and Visean A (VisA) formations. As the volume of injected gas increases, the neighboring producers observe gas breakthrough with increased GOR. The high-GOR wells need to be shut in to achieve maximum oil production in the plant. As the number of shut-in wells increases, however, it becomes challenging to meet plant capacity because of a lack of active producers, resulting in loss of production. To avoid production loss, zonal-production and injection-control capability were introduced through conformance-control completions and use of swell packers and sliding sleeves. With completions closed at a high-GOR interval, oil production is expected to be maintained while gas production from the well is reduced. With the extension of the SGI project, capability will exist to control vertical conformance with the planned completion strategy in 38 producers. In addition, 17 injectors also will have vertical conformance-control capability for selective zonal injections.

Autonomous ICDs Optimize Production in Singue Field, Ecuador

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210417, “Autonomous ICD Introduction in Singue Field, Ecuador: Completion Methodology and Production Evaluation,” by Alejandro Chacon, SPE, Georgina Corona, and Juan Pico, Halliburton, et al. The paper has not been peer reviewed. _ Autonomous-inflow-control-device (AICD) technology, design methodology, and production-performance evaluation for AICD completions were applied for the first time in multiple horizontal wells of the Singue oilfield development in Ecuador. The analysis described in the complete paper covered the complete cycle, from reservoir modeling, completion design, post-drilling match, calibration, and production-performance analysis. Background and Field Information Singue is a field in a tropical rainforest in the Sucumbios province of Ecuador. The first well in the Singue field was drilled in February 1991. Lower U was the target reservoir in this first well. The well was drilled on the basis of seismic 2D data acquired from 1979 to 1989. Field cumulative oil production between 1991 and 1997 was 447,000 bbl. The field then was shut in until 2012, when Gente Oil Company was assigned as the operator of Block 53. Despite heavy field-development investment, a cumulative oil production of 8 million bbl was generated until 2018. Alternate completion techniques were considered to increase oil production by drilling horizontal wells. Water breakthrough was the challenge in these wells. The field has strong support from a water aquifer. An additional challenge in this area was the environmental sensitivity of the Amazon region to produced-water disposal. A horizontal completion with inflow-control technology to restrict water was considered as a mitigation measure. The first horizontal well, AH1, was drilled in 2019; it included swell packers and AICDs to balance the oil and control and restrict water at breakthrough. The second well, BH2, was drilled in 2020; the third and fourth wells were drilled in 2021 with similar completion technology. These wells were drilled in the Lower U reservoir, which has an average oil API gravity of 22.8. This reservoir is considered a consolidated sandstone with no sand production. Fluidic-Diode AICD Technology AICDs have a similar performance to traditional ICDs during the initial oil-production phase of the well before the onset of unwanted fluids (water/gas). During oil production, AICDs induce a low-pressure differential that allows balancing the flow across the completion. Therefore, they also provide the benefit of delaying the onset of water or gas. However, this technology offers additional benefits. In contrast to ICDs, AICDs induce a higher restriction for water or gas by creating a greater pressure differential across the devices for these fluids, which reduces the flow rate when compared with traditional ICDs.

Design and construction of test facility for evaluation of swell packers in cased and open holes

In the petroleum industry, packers refer to the components/products which are used to isolate one section in a formation from others, or to isolate the outer section of a production tubing from the inner section, which may be a casing or a liner or the wellbore itself. Mechanical packers are installed through some form of tubing movement. Permanent packers are low in cost and provide better seal. Retrievable packers have lower sealing capability but are re-usable after repair, and therefore expensive. More innovative packers made of swellable elastomers are rather new. These elastomers swell when they come in contact with different types of fluids (mostly water and oil). Like a casing, these new packers are lowered to the desired depth and allowed to swell before production or injection operations begin. Various studies have been published about the swelling and mechanical response of these elastomers. However, many questions remain about the sealing performance of swell packers, and their effectiveness in actual wellbores of rough and random profiles. This paper describes the design and development of an experimental unit for performance testing of a mix of inert and swelling elastomer seals under realistic well conditions. Actual swell packers and petroleum tubulars are housed in a concrete block that replicates open-hole and cased-hole wells through layers of varying roughness. This is a one-of-its-kind unit providing full-scale demonstration about the working of swell packers against outer casing or rock formation in a wellbore. It is also a complete testing apparatus to investigate the behavior of swell packers made of fast-swell and medium-swell elastomers, and how they seal off irregular boreholes. This work can provide basic understanding and visual corroboration to petroleum engineers and students, swelling elastomer application developers, and academic and research personnel.

Customized Solutions for Coiled Tubing Interventions in the Bolivian Sub-Andean Basin

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202620, “A Review of 25 Coiled Tubing Well Interventions: Customized Solutions for Bolivian Sub-Andean Basin,” by Jovanny A. Hernandez, SPE, Luis F. Antelo, SPE, and Carlos D. Rodriguez, Halliburton, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Fields in the Bolivian Sub-Andean Basin are remote and difficult to access. The producing zones include the country’s most challenging wells, with depths of up to 26,000 ft, with high pressure/high temperature (HP/HT), high gas cut, crossflow, dogleg severity, and well-access restrictions. The complete paper reviews 25 coiled tubing rigless well interventions (CTRWI) to extend the life of those wells, including operations involving nitrogen (N2) lift, acid wash, milling, shifting sleeves, setting packers, stimulation, velocity strings (VS), and fishing. Introduction CTRWI in Sub-Andean Basin fields had not been implemented historically because of limited road access to the fields, lack of available equipment with high technical capabilities, high pressure, and well depth. Beginning in 2017, however, operators evaluated the risk and elected to perform CTRWI involving stimulation, cleanout, N2 lift, fishing, VS jobs, and other techniques. Equipment with specialized capabilities was requested to address the operational requirements and the ability to travel on the remote roads while respecting transit regulations limiting maximum weight to 55 tons. The challenges to transporting equipment economically include - Transportation of large reels of 2⅞-in. coiled tubing (CT) string to complete dual-sectioned VS installations - Transportation of CT unit with 6,600 m of 1¾-in. CT string (weight of less than 55 tons) - Continuously moving large volumes of N2 to the field Wells in these fields were drilled no more than 10 years ago. The majority were built with smart completions, several production layers separated with swell packers and flowing through sliding sleeves configured with the same direction of actuation for opening and closure. Completions are configured with production tubing sizes of 7, 5, 4½, and 3 in. The tubing and accessories are made from chrome 13 because of the presence of carbon dioxide in the production fluids. The region includes some exploratory fields having HP/HT conditions and mature fields with declining production. These wells are important for both the operators and the local government because their production represents more than 50% of national production. On-Site Laboratory Testing Characteristics of produced formation water and mineralogy tests of water samples helped identify a calcium carbonate (CaCO3) scale type. Because CaCO3 scale is known to be acid-soluble, a tailored acid-treatment system was selected with a static formation temperature between 220 to 286°F. On-site laboratory tests using a combination of 13% acetic and 9% formic retarded acid treatment systems were applied to the samples obtained, and results of a solubility test were observed. The selected treatment was demonstrated to be highly effective at dissolving CaCO3 scale according to the test made at the wellsite. High confidence was placed in the test results of the acid-treatment sample because dissolution was above 85% in a 4-hour test period under static well temperature.

Long-Term Performance Assessment of Swell Packers Under Different Oilfield Conditions

AbstractSwelling elastomer seals and packers provide effective zonal isolation in difficult oil and gas fields, resulting in significant savings in rig time and development expenses. Companies involved in petroleum engineering applications provide no information about the longevity or endurance of swelling elastomer packers when exposed to different conditions in the well. This paper describes the design and construction of a test facility for long-term performance assessment of actual full-scale water and oil-swell packers, and the results of the 5-year study. The ten packers are made of three types of swelling elastomers, are kept in crude oil and saline solutions at room and high temperatures, and are exposed to varying high pressures. Regular logs of readings were maintained over the whole study period. Earlier sealing was observed in elastomers immersed in low-salinity water and subjected to high temperature. Rate of swelling was higher in water-based elastomers than in oil-based seals. One packer never sealed completely. Pressurized tubes either retained sealing the whole time or re-sealed after removing of pressure or reducing it to a lower value. Results for the fast-swell and medium-swell elastomer, low- and high-salinity water and crude oil, and low- and high-operating temperatures were mostly in line with short-term tests on laboratory samples published earlier. This unique longevity assessment study can be used by drilling engineers and developers in assessing the suitability of swelling elastomers for target fields and in improving the design of swell packers.

Tuning the mechanical properties of MgO filled epichlorohydrin elastomer composites through in-situ alteration of filler structure using water as stimulus

Water responsive elastomer composites were developed via in-situ chemical modification of the filler in the elastomer matrix where water molecules triggered a tunability of mechanical properties in elastomer composites. In this case, the in-situ transition of the active filler magnesium oxide (MgO) into magnesium hydroxide (Mg(OH)2) in water-swellable elastomeric blend consisting of epichlorohydrin-ethylene oxide-allyl glycidyl ether terpolymer (GECO) and ethylene oxide-propylene oxide-allyl glycidyl ether (GEPO) was studied. SEM and XRD validated the chemical and morphological transition of MgO to Mg(OH)2 in the hydrated elastomer composite. Additionally, on hydration, the treated elastomer's thermal stability is enhanced by 30 °C compared to the untreated elastomer composite. Stress-strain and DMA analysis results showed that the active filler's in-situ chemical transition in the matrix tuned the elastomer composite's mechanical properties. Tunability in Young's modulus by 221 %, M200 (Modulus at 200 % strain) by 80 %, and dynamic modulus at room temperature by 900 % are observed for 48 h water treated elastomer composite compared to untreated composite. Conceptually, this water responsive elastomer could find application in swell packers, marine sealants, adaptive medical implants and automobile industries.

Improvement of the efficiency of horizontal wells

The research purpose is to identify factors of premature flooding of wells, assess the influence of factors, simulate and compare results obtained with field data. An analysis of the reservoir properties, design and development indicators of horizontal wells showed that only 41% of cases of premature flooding are due to geological causes (heterogeneity of rock permeability). Technological reasons (high specific samplings) occur in 36% of cases, this problem is pronounced in wells where new technologies were implemented – division of the wellbore into sections using water and oil swell packers. In 23% of cases, premature flooding is due to wellbore drilling in the water-saturated zone.

Optimization of hybrid oil/water‐swelling ethylene/propylene/diene monomer compounds

AbstractHybrid swell packers are rubber products capable of swelling in (saline) water and hydrocarbon oils, by exploiting the hydrocarbon diffusion properties of an nonpolar elastomer with the osmotic swelling of a water absorbent (WA). In this study, a variety of modified natural and synthetic WAs and mixtures thereof have been screened in a rubber compound with respect to swelling in decalin, demineralized, and saline water, respectively. We aimed at achieving high and fast swelling in all used media. Mixing of the various WAs in an ethylene/propylene/diene monomer (EPDM)/carbon black masterbatch at an addition level of 75 phr did not pose any problems, although it was found that the WAs did affect the sulfur vulcanization. Decalin swelling of the vulcanizates is very fast, reaching high equilibrium swelling within 1.5 days. Swelling in demineralized or saline water is much slower, with up to 300% swelling in water and up to 100% swelling in saline water. Significant leaching of the organic WA from the EPDM vulcanizates to the water phase occurs. Some combinations of WAs show synergetic effects for swelling in water. To our knowledge, such a systematic study of hybrid swelling elastomers constitutes a novelty in the open literature.

Performance evaluation of swelling elastomer seals

Swell packers are now being widely used for increased recovery from difficult oil and gas reservoirs and for remediation of various well problems. It is important to know how the elastomer actually swells in a particular well, how much time is required to achieve sealing, and what sealing pressure is generated. No published work is available that numerically investigates elastomer seal performance based on actual material properties at various stages of swelling. Current work uses finite element simulation to investigate swelling elastomer seal behavior in downhole petroleum applications. Variations in sealing pressure are studied for seal length, seal thickness, compression ratio, water salinity, swelling time, and type of well completion. Month-long swelling experiments on samples of two actual elastomers provide input to the numerical model in terms of real material and deformation data. Contact pressure was found to increase with swelling, at a higher rate in the first few days, then more slowly. Higher sealing pressure was observed in the case of swelling in lower-salinity brine, larger length of the sealing element, higher compression ratio of the seal, and elastomer swelling against rock formation as compared to steel outer-casing. These results can help field engineers decide which swelling elastomer and what seal configuration to use under a given set of field parameters. The study can also be used by application designers and academic researchers as a starting point for swelling elastomer based seal design and analysis.

Multizone monitoring well completion design in the GAB

To provide the community with assurance that Santos GLNG operations are performed in a safe and responsible manner, the company has undertaken a major project to equip a large number of boreholes with multizone aquifer monitoring systems. These systems ensure aquifer water levels are monitored accurately. To provide a cost-effective design that reduces the need for multiple wells and provides long-term data reliability, a packer and gauge system with full redundancy was designed and co-developed with Santos. The focus of this design was zonal isolation between aquifers, full redundancy, and retrievability. This extended abstract describes a project where a fully retrievable seven-zone system was designed, deployed and monitored. Although the swell packers used to isolate zones are a mature technology, this is the first application where they have been designed to be recovered from the borehole with a pull-to-release system. The design and deployment was especially complex as both the retrievable packers and 14 pressure temperature gauges were deployed in a slim 4 inch bore. The system was successfully deployed in the first quarter of 2014. A compact solar power surface acquisition system has also been integrated. It gathers and transmits the borehole data to an online portal. Santos is fully transparent with the data gathered and the local community is able to get this data from the online portal.

Investigation of Pre- and Post-Swelling Behavior of Elastomeric Material

In the last ten years, a new type of modern polymer, known as swelling elastomer, has been used extensively as a sealing element in the oil and gas industry. These elastomers have been instrumental in various new applications such as water shut off, zonal isolation, and sidetracking. Though swell packers can significantly reduce costs and increase productivity, their failure can lead to serious losses. The integrity and reliability of swelling elastomer seals under different field conditions is a major concern. The investigation of changes in material behavior over a specified swelling period is a necessary first step for performance evaluation of elastomer seals. The current study is based on experimental analysis of changes in geometric and mechanical behavior (hardness, tensile, compressive, bulk) of an elastomeric material due to swelling. Tests were carried out before and after various stages of swelling. Specimens were placed in saline water (0.6% and 12% concentrations) at a temperature of 50°C, with the total swelling period being one month. Swelling, hardness, compression, and bulk tests were conducted using disc samples, while ring samples were used for tensile experiments. A small test rig was designed and constructed for determination of bulk modulus. Stress-strain curves under tension and compression, and pressure volumetric-strain curves were obtained for specimens subjected to different swelling periods. Due to the fast-swell nature of the elastomer, there were sharp changes in mechanical properties within the first few days of swelling for both salinities. Elastic modulus derived from tensile and compressive tests showed a 90% decrease in the first few days. Bulk modulus showed fluctuation in its variation with an increasing swelling period. There was a small effect of salinity only during the first 5 or 6 days.

Coupling Reservoir and Well-Completion Simulators for Intelligent Multilateral Wells

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 164815, ’Coupling Reservoir and Well-Completion Simulators for Intelligent Multilateral Wells: Part 1,’ by G.A. Carvajal, N. Saldierna, M. Querales, SPE, K. Thornton, SPE, and J. Loiza, Halliburton, prepared for the 2013 SPE Europec/ EAGE Conference and Exhibition, London, 10-13 June. The paper has not been peer reviewed. To maximize well productivity and reservoir oil recovery in mature fields, advanced lateral designs with intelligent completions have been implemented during the last decade. This paper describes an all-in-one system that combines nodal-analysis and numerical-simulation models to calculate the effect of intelligent-completion components—such as swell packers, internal control valves (ICVs), and inflow-control devices (ICDs)—on lateral production profiles. A 3D-grid, multiphase-flow, nonisothermal reservoir numerical simulator was used for advanced well design, and a wellbore nodal-analysis simulator was used to solve the partial-differential equations between the porous medium and the wellbore. Introduction Multilateral wells are often the best choice to maximize reserves recovery and contact with the reservoir and to extend the drainage area. However, several studies have revealed that multilateral wells exhibit a series of natural issues (e.g., high influx at lateral heels because of pressure drops). As a result of such issues, increased water or gas production can decrease oil production over time. Use of intelligent-valve technology can mitigate these problems significantly. Reservoir Complexity and Heterogeneity The reservoir model used here is a synthetic reservoir with an almost constant porosity of 20% and significant areal permeability variation from 1 to 500 md. The main depth is 8,000-ft true vertical depth subsurface. The net pay is 100 ft, and net/gross ratio used for the simulation is 0.8. A 3D sector numerical- simulation model was built with the following dimensions: x=100 cells, y=50 cells, and five layers, for a total of 25,000 cells. The areal permeability distribution is taken from a geostatistical model. The permeability distribution is con-strained by spatial carbonate-facies distribution honoring log and core data of injector and producer wells in the sector model. Reservoir-quality index (RQI) is calculated to screen areas with best reservoir quality; an area where RQI equals 10 is considered the best area to place multilaterals. However, the reservoir exhibits strong permeability contrast, not only among layers but also inside the carbon-ate body, as shown in Fig. 1.

Nikaitchuq Extended-Reach Drilling: Designing for Success on the North Slope of Alaska

Summary A 52-well heavy-oil field development that targeted shallow—a 3,400- to 4,000-ft true vertical depth (TVD)—sands on the North Slope of Alaska was initiated in 2008. Horizontal wells of 11,000- to 13,000-ft measured depth (MD) were drilled early in the program. These initial wells served as "data-gathering and technology-proving" opportunities leading up to the eventual 23,000-ft-MD wells. Key technical challenges include equivalent-circulating-density (ECD) and drag management. ECD management became essential in the 8½-in. production-hole section of the longer wells. A relatively narrow (<600 psi) mud-weight (MW) window necessitated changes to casing, drillstring, drilling fluids, and operational parameters. Lighter-weight production casing allowed the drilling of a larger production hole (8¾-in. vs. 8½-in.). A tapered drillstring, reduced mud rheology, and reduced flow rate all became a necessary part of the ECD-management solution. Advanced drag-management techniques are required to install the 9⅝-in. production casing, 5½-in. production liner, and 4½ × 3½-in. intelligent inner-string completion. The 9⅝-in. casing is installed by use of the "buoyancy assist" method (i.e., "flotation") so it may be "pushed" and reamed in the hole beyond the point of negative weight. The lower completion consists of a 5½-in. slotted liner with swell packers. Centralizers on the liner were changed from nonrotating to fixed, which allowed breaking axial drag while reaming the liners to depth. Extensive torque-and-drag modeling was used to plan intelligent inner-string completions on the injector wells, which included injection control devices, swell packers, and a fiber-optic distributed temperature sensor (DTS) to monitor injectivity. This full-length paper discusses the technical challenges, well-design solutions, and operational practices that were trialed and implemented to enable extended-reach wells to be successfully drilled on the edge of the industry-experience envelope, with all wells meeting targeted objectives.

Design and Manufacture of Swell Packers: Influence of Material Behavior

In all well completions (oil and gas fields), effective cement job is necessary for zonal isolation. Failure of cement annulus because of large stresses has been reported in various studies, requiring huge costs in remedial intervention. Swellable packers have emerged as a new manufacturing equipment/technique able to replace conventional cement completion. These packers are custom-manufactured by vulcanizing specially developed swelling elastomer elements onto petroleum pipes. Especially designed and manufactured to suit a particular set of downhole conditions, swell packers are being used in a variety of petroleum applications such as zonal isolation and water shutoff in fractured reservoirs, slimming down of oil wells through replacement of conventional cementing, sand screening, reservoir compartmentalization, etc. Performance analysis and seal design improvement is not possible without reliable information about material response of swelling elastomers. This article summarizes the results of a series of tests performed to determine the swelling behavior of a water-swelling and an oil-swelling elastomer, with and without acid induction. Experimental setup was designed in consultation with petroleum and rubber engineers. Volume, thickness, and hardness of elastomer samples were measured before swelling and periodically after swelling over a one-month period. Test conditions were chosen to replicate actual oilfield conditions.

Saudi Arabian Trilateral Oil Well in an Unconsolidated-Sandstone Reservoir

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 120999, ’The First Saudi Arabian Trilateral Oil Well in Unconsolidated-Sandstone Reservoir,’ by Ali S. Raba'a, SPE, and Anthony S. Johnson, SPE, Saudi Aramco, and Keith Parry and Mohammed A. Abduldayem, SPE, Weatherford, prepared for the 2009 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 4-6 August. Multilateral (ML) wells to achieve maximum reservoir contact (MRC) are used widely in new carbonate-field developments in Saudi Arabia, resulting in substantial financial improvement of these assets. A multidisciplinary approach was used to evaluate, plan, and complete the first trilateral well in a heterogeneous unconsolidated-sandstone reservoir in Saudi Arabia. The objectives of the ML well were to maximize reservoir contact to enhance sweep efficiency, to improve well productivity, and to promote ML-well applications in this complex field to extend the field’s production plateau. Introduction The objective of ML-well technology is to improve well productivity, either by maximizing reservoir contact in a single reservoir or by commingling production from two or more producing zones or formations into a single main wellbore. Successes with this well architecture justified extending its use into an oil field in central Arabia. The Permian heterogeneous unconsolidated-sandstone reservoir consists of well-developed eolian sandstones and closely associated interdune and lacustrine deposits. Maintaining wellbore stability while drilling this friable-sandstone reservoir presents a considerable challenge. Wells must be equipped with downhole sand control and electrical-submersible-pump (ESP) artificial-lift systems, which cannot tolerate appreciable solids loading. The candidate well for ML drilling was an idle vertical well that had been shut in because of high water cut (WC) and low productivity. Reservoir characterization and fluid-contact information from adjacent wells were uncertain. Before drilling the laterals, a deviated pilot hole was drilled across the entire reservoir, which provided valuable data that helped optimize placement of the laterals. Re-entry of an existing well to drill and steer three long horizontal open drain holes into the reservoir imposed several constraints and added challenges. The well completion involved installing an expandable sand screen (ESS) in the main bore and standard sand screens in the two laterals to facilitate sand-free commingled production from all three laterals. The lateral completions included a wash-down capability in the high-build-angle laterals and incorporated swell packers positioned just inside the laterals to ensure sand-tight conditions at the Technology Advancement Multilateral (TAML) Level-3 junctions. Horizontal-Well Infill Strategies Several drilling strategies have been applied in the field. Initially, the field was developed with vertical wells at 1-km well spacing and with peripheral water injection. Most wells are equipped with an ESP for oil production. After 5 years of production, a new horizontal-sidetrack infill strategy was implemented to target unswept oil, access low-permeability pay, reduce the WC, and accelerate oil production. Geosteering to intersect the top of the reservoir (shallow horizontal sidetracks) or to follow individual channels was found to be ineffective because of the heterogeneous nature of the reservoir (low vertical conformance) and difficulties in predicting sand presence and continuity. Therefore, the integrated team developed an optimal sidetrack infill strategy of highly deviated wells with minimal geosteering.

Swelling Packers Solve Zonal-Isolation Challenge in Oman High-Pressure Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100361, "PDO's Proactive Approach To Solving a Zonal- Isolation Challenge in Harweel HP Wells Using Swell Packers," by M.S. Laws, SPE, (now with Shell Abu Dhabi B.V.), J.E. Fraser, SPE, and H.F. Soek, SPE, Petroleum Development Oman, and N. Carter, SPE, Easywell UAE (now with Sensornet Ltd.), prepared for the 2006 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Bangkok, Thailand, 13–15 November. The Harweel cluster of reservoirs in southern Oman is Petroleum Development Oman's first enhanced-oil-recovery project. Zonal isolation is crucial to the success of the planned miscible-gas-injection project. Previous isolation attempts using cementing technology alone have proved to be unsuccessful. On the basis of results obtained from both laboratory and field tests, swelling packers in combination with cement have demonstrated zonal isolation in these challenging high-pressure reservoirs. This could enable a significant increase in reserves and, hence, ultimate recovery in these fields. Introduction The Harweel cluster consists of nine different deep, highly pressured reservoirs containing sour, light hydrocarbons. More than 50 wells have been drilled in and around these fields. The initial wells have a shallow 13 3/8-in. surface casing, a long 9 5/8-in. production casing, a 7-in. liner cemented over the reservoir section, and 3 1/2-in. production tubing. The cluster is being developed in a phased manner. The objective of Phase 1 was to gather data from a number of different sources to determine if a miscible-gas-injection project would be feasible in some of these fields. Phase 2 will involve primary depletion in a number of fields followed by gas injection in some, and Phase 3 will involve clusterwide depletion and gas injection in the remaining fields. To maximize ultimate recovery from these fields, gas (and water) shutoff is required during Phases 2 and 3 of the project. For this to be effective, zonal isolation over the reservoir is essential. A substantial effort has been expended during construction of the Phase 1 wells to determine if zonal isolation was being achieved with standard cementing techniques. Cement-bond logs were run over the liner section in every well to determine cement quality. These logs showed that a microannulus was being created in practically every case. During well completion, cement debonding from the production liner occurs as a result of differential-pressure effects that lead to creation of a microannulus. Once the microannulus is created, a permanent flow path between the cement and production liner can be created, preventing zonal isolation. Selective perforating during the subsequent well-testing campaign showed that this microannulus was conductive to reservoir fluids (Fig. 1). In one incident, reservoir fluids leaked all the way to surface through the microannulus.

Techbits: Developing Marginal Offshore Fields

Penang, Malaysia, was the site of the SPE Applied Technology Workshop (ATW) on "Development of Marginal Offshore Fields" held 24–27 July. The ATW was attended by 76 participants, representing 42 different organizations from 13 countries. Following an opening address by Dato' Koay Kar Huah, Executive Councillor, State Government of Penang, the stage was set for seven technical sessions by Ramlan Malek, General Manager-Petroleum Resource Development for PETRONAS, with his keynote speech "Opportunities and Challenges of Marginal Field Development in Malaysia." The following points were captured during the technical sessions. Commercial Formulas for Economic Understanding, Risk Protection, and Value Gain. In the past, Malaysia adopted a volume-based commercial arrangement for production-sharing contracts (PSCs). With smaller discoveries, fluctuating oil prices, and uncertainties in costs, PETRONAS introduced a profitability-based commercial arrangement through revenue-over-cost PSCs. A case study was presented to demonstrate that such a change in commercial arrangement can improve the economics of small-field development significantly. Managing Commodities Price Risk for Marginal Petroleum Projects. There are a number of ways to man-age commodity prices for marginal petroleum projects, including insurance and hedging. Oil-price projection is normally lower than the actual oil prices. Rapid Oil Development (ROD). ROD is one of the tools available to quickly monetize stranded small oil fields that are isolated from existing infrastructure. Facility deployment can be achieved as quickly as 6 to 9 months. ROD needs as little as 2 to 3 million bbl of oil to make it attractive. Such a concept can prove the reservoir characteristics and volume earlier. Innovative Facilities Solutions To Reduce Capital and Operating Costs. Presentations and discussion took place on these topics: "Implementation of Innovative Multiphase Boosting and Production Technologies for Marginal Offshore Fields," "Relocateable Topsides," and "Seamless Fast Tracking of Engineering, Procurement, Installation, and Commissioning Projects for Marginal Offshore Fields." East Belumut Development-Well Completion Design and Issues. A case study on the background to the above field development and details on the reservoir and fluid characteristics was presented. The need for extended-reach wells, the low rock strength, thin oil column, high viscosity crude, gas cap, and underlying water all combine to make the development complex and marginal. The currently proposed sandface-completion design incorporates standalone sand screens with inflow/pressure-control devices, swell packers, and centralizers for management of potential sand-production problems and to increase production control along the length of the screens. The upper completion is composed of 3½-in. tubing with gas lift mandrels and a subsurface safety valve. The operation is relatively simple, with the tubing stabbed into the liner/sand-screen polished-bore receptacle and no production packer. Following the presentation, general discussion took place on the various completion philosophies. Questions on the design process and the rationale behind the selection of swell packers, standalone sand screens, and flow-restriction devices were answered.

Next Generation of Sakhalin Extended-Reach Drilling

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 99131, "The Next Generation of Sakhalin Extended-Reach Drilling," by R.A. Viktorin, SPE, J.R. McDermott, R.E. Rush Jr., SPE, and J.H. Schamp, SPE, ExxonMobil, prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21-23 February. Six of the longest-reach wells in the world have been drilled in Chayvo field on Sakhalin Island. Revised completions used standalone screens (SASs), pre-drilled liners, and swell packers to achieve a low-damage, sand-free completion with zonal isolation. Bit designs, bottomhole-assembly (BHA) configurations, and operations practices were modified to minimize the amount of backreaming, improve the overall rate of penetration (ROP), and achieve a "one-pass trippable hole" (OPTH). Improving rotary-steerable-system (RSS) reliability could eliminate trips to replace the tools. Introduction The Chayvo field development plan comprises 15 onshore extended-reach-drilling (ERD) wells with measured-depth (MD) reaches of 8 to 10 km and 18 offshore directional wells drilled from an ice-resistant platform. The focus of this paper is the Chayvo onshore ERD operations that began in July 2003. At the time this paper was written, eight of the 15 land-based ERD wells had been drilled from the Chayvo wellsite (Fig. 1). The full-length paper details design changes and operations optimization that evolved into the next generation of ERD wells at Sakhalin. The typical Chayvo ERD well design is shown in Fig. 2. Completion Design Evolution The original completion design met the following objectives.Low-damage completion capable of producing 25,000 BOPD.Providing zonal isolation to mitigate risk of gas and/or water breakthrough.Sand-free completion.Provide low-risk interventions. The first four Chayvo completions were designed to achieve these objectives by use of a rotated and cemented 7-in. liner tied back with 7-in. tubing. These 7-in. monobore completions enabled oriented underbalanced perforating with coiled tubing, thereby reducing potential for sand production and providing a low-skin completion. Although this design achieved all the objectives, implementation proved difficult because of liner-cementing and perforating problems. Running the 7-in. liners on the first four wells was trouble-free. However, problems occurred in two wells while filling the liner with mud, and the other two wells had cementing problems. Redesign. Completion redesign focused on reducing nonproductive time (NPT) caused by failures in the liner installation and problems with perforating. Design options included openhole completion, openhole gravel pack, cased-hole gravel pack, and SAS. Fig. 3 compares the new and old completion designs. The new design uses external-isolation swell packers and SASs with inflow-control devices (ICDs), which were not proven or available for the original completion designs. The new design positions SASs across the weaker, more permeable formation to provide a sand-free completion. These SASs use ICDs (or chokes) to reduce flow from the high-permeability formations that could produce gas or water if allowed to produce unrestricted. The high-permeability intervals are isolated from the low-permeability intervals with swell packers. The higher-strength low-permeability intervals are completed with a predrilled liner. Swell packers replaced cement for zonal isolation, and ICDs replaced selective perforating to control flow from high-permeability zones. The key to successful zonal isolation was positioning swell packers and screens precisely across the high-permeability zones.

Coiled-Tubing Operations in the Panna Field Offshore Western India

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100149, "Operability Challenges During Coiled-Tubing (CT) Well Intervention: Panna Field Case Histories From Western India Offshore," by S. Kale, SPE, and R. Proctor, SPE, BJ Services Co., and S. Paliwal, SPE, and S. Nayak, SPE, BG E&P India Ltd., prepared for the 2006 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 4-5 April. Coiled tubing (CT) was used in well interventions offshore western India. Well completions are open hole, open hole with tail pipe, and cased hole with swell packers. CT entry was essential to operate sliding sleeves installed in the completions. The full-length paper documents case studies and reviews attempted solutions such as bottomhole-assembly (BHA) excitation tools and contact-friction reducers to extend reach and increase downhole force. Introduction Located off the west coast of India, the target reservoir in the Panna field is a limestone layer. Horizontal wells have been drilled and completed in the field since 1997. The main difference between the wells completed in the late 1990s and current wells is the horizontal-section length. Challenges associated with CT operations can be considered as logistical and technical. The main logistical challenges include limited crane capacity and deck space for CT rig up. Technical challenges include limited CT downhole force. Because of logistical challenges, the preferred CT size cannot be used on most platforms. Logistical Challenges Panna field has two types of platforms, one with nine slots and the other with 15 slots. The nine-slot platforms have limited deck space and crane capacity. Larger CT sizes such as 1 3/4-in.-outside-diameter (OD) pipe cannot be rigged up on nine- slot platforms but can be used on the 15-slot platforms. Two memory-production-logging (PL) campaigns were undertaken on the 15-slot platforms. Because of limited deck space on some platforms, fluid-pumping and nitrogen equipment, tanks, and mixing equipment were offloaded to a dedicated supply boat as required. This presented the logistical challenge of timing the operations to boat availability and tide conditions. Technical Challenges The two most important technical challenges faced by the team were CT-reach prediction and identification of possible solutions to meet well-intervention objectives. The objectives of well interventions in late-1990s completions were acid stimulation and memory PL. Current completions require sliding-sleeve manipulation, acid stimulation, and PL. Accurate CT-entry predictions require use of a CT simulator. In addition, the engineer using the simulator must have a thorough understanding of the modeling parameters and analysis process.