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Collaborating Authors
International Petroleum Technology Conference
Abstract The Temana field consists of unconsolidated reservoirs which require active sand control. Conventional Internal Gravel Packed (IGP) technique has been widely applied as it has provided a reliable means of abating sand production. These completions however, have shown high skins (>15) which had increase with time due to fines migration into the packed area especially with the advent of water production. In many cases, flow efficiencies were reduced by 70% and this had severely affected well performances with aging. Stand Alone Screens (SAS) and Expandable Sand Screens (ESS) had also been applied in some fields with mixed success especially for high angle or horizontal wells. Experience gathered from these previous sand control measures coupled with the emergence of improved design and production of SAS has enabled a shift in our sand control philosophy. Critical Drawdown Sanding Pressure (CDP) consideration plays an important role in the new sand control strategy we recently applied. To ensure that the CDP does not exceed during well production, we focus our attention to maximize well productivity by implementing open hole completion at high angle of trajectories (70 deg or even horizontal). Furthermore, the reservoir sections were drilled with non damaging drill-in fluid treated with enzyme breaker and screens were run in conditioned, solids free mud to minimise plugging. Proper sizing of the screen slot size is critical to ensure that screens are not plugged as commonly experienced in SAS applications. Annular flow were minimised by running constrictors suitably placed with the screen assembly. Finally, strict enforcement of slow bean-up policy during the initial production of the new wells has maintained the screen's integrity in the wells completed so far. This paper describes our new sand control application and the excellent production performances achieved from the new wells in the recent drilling campaign in Temana. Introduction Temana field was discovered in 1962 and brought into production in 1979. The field is located approximately 30 km West of Bintulu in a water depth of approximately 96 ft. It consists of three hydrocarbon accumulations, namely Temana West, Temana Central and Temana East (Fig. 1). The field has undergone a complex tectonic history and is highly faulted and compartmentalized. The latest development is from the existing structure Platform A, which penetrates the Temana Saddle, which is located in the southeastern part of Temana Central. The main reservoir target is the I-65 sand. The sand has a fining upwards log signature with a sharp base at the bottom of the sand. The sand contains light oil of about 41.1 deg API with reservoir pressure of 1,553 psi, average porosity of 26% (oil) and effective permeability of more than 1 Darcy. The main drive mechanism of this reservoir is depletion drive with weak to moderate aquifer support. There are 7 existing platforms (Fig. 2) with two additional production processing facilities platforms. About 44 wells out of 74 wells of the existing oil producer wells were completed with cased hole gravel packed (IGP) and only 2 wells were installed with premium screens in horizontal open holes. Based on the well test data for these wells for a similar type of reservoir, the average skin is 10–15 even after immediate production and increase up to 20–30 after longer years of production. The average PIs of these wells typically ranged between 1–20 stb/d/psi. Investigation shows that the eminent cause of increasing skin or pack impairment and deterioration in the production wells is due to fines movements packing into the gravel-packed sand and this was aggravated when water breaks through.
- Europe (1.00)
- Asia > Malaysia > Sarawak > South China Sea (0.81)
This paper summarizes ExxonMobil‟s redevelopment of a severely drawn down and challenging gas field in Malaysia. The drilling campaign tackled the prolific Jerneh field, marked by significant depletion and fracture gradients as low as 8.0 ppge. Previous campaigns experienced severe lost returns, stuck pipe, and escalating costs. ExxonMobil‟s global drilling organization was leveraged, which resulted in the development of new lost returns technology utilizing ExxonMobil‟s fracture closure stress (FCS) technology to help achieve the campaign‟s objectives. This technical and organizational effectiveness resulted in optimum well designs, proper risk management, and ultimately the successful field execution of the complex campaign. The paper will describe the key planning and execution details of the redevelopment campaign including: ExxonMobil‟s global drilling organizational and technical capabilities drawn on to leverage success including use of various company technologies Multi-function collaboration and risk management to achieve sound drill well designs and disciplined execution at the field level Fundamental rock mechanics that support building near wellbore integrity while drilling with high filtration rate, stress building fluid to enhance integrity (as opposed to a low fluid loss system) Engineering and operational practices to mitigate inherent risks associated with the high fluid loss drill and stress fluid system Crew training, operational execution, and actual field results The application of these principles and procedures resulted in campaign success and controlled costs through the elimination of contingency casing strings, effective minimization, and mitigation of lost returns, and prevention of differentially stuck pipe in this very challenging, mature gas field drilling campaign. This success also proved up additional gas resources, including the installation of the second Jerneh field platform and its development drilling campaign (currently in progress).
- Geology > Geological Subdiscipline > Geomechanics (0.48)
- Geology > Rock Type > Sedimentary Rock (0.46)
ICD Screen Technology in Stag Field to Control Sand and Increase Recovery by Avoiding Wormhole Effect
Kvernstuen, Svein (Reslink AS) | Dowling, Keith Robert (Apache Corp.) | Graham, Joseph Samuel (PetroPerth) | Chechin, Alexander Vladimirovich (Apache Energy Ltd.) | Porturas, Francisco (schlumberger) | Wibawa, Sandya (schlumberger)
Abstract This paper presents the first installation of nozzle-based passive inflow control devices (ICD) for Apache Corporation in Australasia. This recent technology was simultaneously applied in a production well and a water injection well, and served as a demonstration of its potential benefits in the development of Stag oilfield. Located offshore in the North-West shelf of Australia, Stag field is a shallow and unconsolidated glauconitic sandstone reservoir with a top and bottom sealing shale. The reservoir pressure is low and it contains heavy and viscous oil of 19º API - 9 cP. This causes sand production, high water cut, wormhole development and requirement for artificial lift, increase drainage area and improve sweep efficiency. In the early stage of field development a reservoir failure was observed. A documented investigation indicated that the failure mode appeared to be wormhole-like failure2. To date, there have been several failures with similar characteristics occurred in Stag field. Water injection post wormhole-like failure has been reported very inefficient as the water passes through to producer via the wormhole channel and does not sweep any oil. Overall horizontal injection wells performance in the field was poor with injection rates typically dropping quickly with constant injection pressure. Increase in injection pressure to bring the injection rate up is limited due to the low formation frac pressure. ICD technology was sought in effort to mitigate these dynamic challenges. It has showed good results and further investigation is ongoing. The paper describes the processes in delivering the tailor-made ICD system, i.e. completion modeling in the reservoir grid to simulation analysis of various scenario and sensitivities. Solution to tight product delivery time, the ICD completion installation and performance evaluation is also discussed. Introduction Stag field background and reservoir challenges The Stag field, operated by Apache Energy, is a reservoir within the M. Australis formation at 2230 ft TVD subsea. The average reservoir pressure is currently around 415 psia with rock strength (UCS) in the range of 0.12–1.03 MPa. Since the commencing field production in 1998 major redevelopment had been undergone to achieve and enhance the field's recovery1. In July 2000 the Stag field reached its peak rates in excess of 30,000 BOPD. Late that year a failure occurred in the reservoir between a horizontal water injector and a horizontal producer, some 2130 ft apart. Both wells were completed with un-cemented pre-perforated liners. A comprehensive investigation by McDiarmid et al2 led to a conclusion that the failure was caused by high stresses in the reservoir compared to the formation strength. The high stresses caused wormhole-like failure, propagating from the producer to the injector. This characterized by large volumes of sand matrix and fine clay particles being produced where water breakthrough. Pulse tests and tracer study indicated that a short circuit had occurred in the reservoir between the two wells, where it took 2 hours 50 minutes to travel from surface to surface. The wormhole dimension was calculated to be greater than a 6 inch equivalent diameter. To date, there have been several failures in the field with similar characteristics where biocide tracer confirmed the direct communication between several producers and injectors. Water injection post wormhole-like failure is very inefficient as the water passes through to producer via the wormhole channel and doesn't sweep any oil. Remedial attempts proved to be expensive and ineffective due to the inability to effectively isolate the targeted formation interval through the un-cemented pre-perforated liners.
- South America > Colombia > N Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-209-P > Stag Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-15-L > Stag Field (0.99)
This reference is for an abstract only. A full paper was not submitted for this conference. Abstract Description This paper describes the project management processes used to design and procure the topsides facilities for the Gumusut-Kakap project. Gumusut-Kakap is a "mega-project" to be installed in Malaysian deepwater to produce up to 150,000 bpd sales quality oil whilst injecting up to 220,000 bpd seawater and up to 300 MMscfd gas to the reservoir. The topsides facilities are thus world-class in scale. They will be supported on a new-build, moored semi-submersible, receiving production from subsea wells. Interfaces between the topsides and the hull, the subsea systems and the export pipeline are complex and are described in the paper. The topsides execution strategy is aligned to the project's drivers: Safety, Technical Integrity, Capability Development, Schedule and Cost. These drivers were enforced throughout the FEED phase which was executed in Shell's US design centre and the Detailed Design phase which was transitioned to a Malaysian EPC contractor to facilitate Capability Development, Schedule and Cost. The challenges, plans and learnings from this transition are described in the paper. The project management processes developed in Shell's deepwater projects group were adapted for the Gumusut-Kakap project and used to support the EPC contractor. Key processes implemented include: Design Verification, Weight Management, Interface Management and Flawless Start-Up, enabled through key Information Technology (IT) tools. These processes and their customisation are described in this paper. The results presented in the paper will be to mega-projects, especially those in areas developing local capabilities. The are:Alignment of stakeholders on the project drivers is vital Contractor capability is a key areas to address in transition planning and capability development Project management processes need to be customised for the particular project The of this paper is through:Base plan for transitioning a design from a company center to the host country Improved techniques for developing capability of key contractors Enhanced tools for managing complex project interfaces Acknowledgement The authors would like to thank the management of Sabah Shell Petroleum Company and their Gumusut-Kakap joint-venturers: Petronas-Carigali, Conoco-Phillips and Murphy Oil for their permission to publish this abstract.
Copyright 2008, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Kuala Lumpur, Malaysia, 3-5 December 2008. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum 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 where and by whom the paper was presented. Abstract Stacked gravel-packs involve limited technical risk, but require considerable rig time when completing deep multi-zone sand control wells. Four field developments are challenging the conventional approach to completing long sand control zones by using newer technologies. A typical well in the Mahakham Delta has five zones and installing conventional gravel pack completions would consume up to 30 rig days. This represents a significant capital cost. To reduce costs, the Operator has completed 19 wells with Single Trip Multi-zone (STMZ) technology. Two different STMZ techniques have been applied because of differing well characteristics and objectives. To date, 14 wells have been equipped with Dual Sting - STMZ completions and five wells have the new Single String-STMZ technology. These 19 wells embody 77 frac packs / gravel packs. The average completion time has been 11.3 rig days/well for DS-STMZ wells. SS-STMZ completions have averaged of 22.2 rig days/well inclusive of NPT and the upper completion.
- North America > Canada > Saskatchewan > Williston Basin > Delta Field > Shaunavon Formation (0.98)
- Asia > Indonesia > East Kalimantan > Makassar Strait > Kutei Basin > Mahakam Block > Nubi Field (0.96)
- Asia > Indonesia > East Kalimantan > Makassar Strait > Kutei Basin > Mahakam Block > Sisi Nubi Field (0.95)
- (3 more...)
- Well Completion > Sand Control > Sand/solids control (1.00)
- Well Completion > Sand Control > Gravel pack design & evaluation (1.00)
Abstract Over the past 3 years, an operator in Malaysia has developed several large-bore gas wells with horizontal trajectories. The completion team was faced with several challenges in designing the completion of these wells, particularly in the area of deploying a plugging device to test the completion string and to set the production packer. Traditionally, two conventional plugging methods have been used ? slickline-deployed plugs or ball-activated pump-out plugs. Due to the deviated trajectories and associated intervention risks, both methods were deemed unfeasible. A coiled-tubing intervention could have been considered, but this method would have added significant cost to the completions. To actualize these wells, therefore, an operator needed to find an alternative method that would provide a low-risk, cost-effective tubing-testing and packer-setting device. An option that would eliminate the problems discussed above, a novel "disappearing plug" plug concept, was presented. This plug is unique in that after usage, the plug material dissolves, leaving full tubing drift. The operator chose this option. The paper discusses the plug design, how it reduced completion costs and risks by eliminating extra trips into the wellbore for running and retrieving plugs or test tools. The discussion also covers the factors an operator considered before choosing the disappearing plug option as well as details of the first installation. This installation provided experience into specifics required for successful usage of the plug as well as best practices. To date the operator in Malaysia has successfully installed 27 disappearing plugs, and no failures to date have occurred. Introduction The field in Malaysia consists primarily of two shallow gas bearing reservoirs, at approximately 2,650 ft TVD. These reservoirs are laterally extensive, covering an estimated area of 200 square km with estimated gas-in-place (GIP) in excess of 2 Tscf. The reservoirs are made up of a sequence of highly laminated sand and shale deposits with significant sand-size variability and high fines content. In late 2004, the operator planned to complete the well, which had a measured depth of approximately 6500 ft with a maximum deviation of 80 degrees. The completion design was to incorporate a 7-in. tubing string with a hydraulic-set packer. A primary completion concern was the need to run a plugging device below the packer so that the packer could be set. A wireline-set plug had been considered, but it was deemed as too risky because of the extreme deviation. When considering the risks associated with running a wireline fishing job in a big-bore completion-string design, the operator decided to look for another option. A ball-activated pump out plug was reviewed; however, in a horizontal big-bore completion, placing a ball on seat presents another tricky challenge, especially when there might be debris in the well. Furthermore, in a big-bore completion, the energy released when the plug expends is very high due to the high fluid volume of the completion string. This usually results in a violent hydraulic impulse which can damage sensitive completion jewelry. Ball-activated pump-out plugs will also introduce debris into the well, as when the ball and seat is expended, the items will remain in the well. Hence, the operator decided to use a different type of plug technology ? an interventionless disappearing plug (Larimore 2000). At that time, the plug had had a 100%-success-rate track record with 25 out of 25 installations having been successful.
- Asia > Malaysia (1.00)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
Abstract It is well established in reservoir description process that coarser scale of the data has less uncertainty associated with it. For example 3D seismic data may provide information about column average porosity data. Many procedures in the literature are developed for integrating such column averages in 3D property distribution. This paper extends the analysis to generating 3D simulation processes where the coarser scale information represents both the facies data and porosity data. Coarse scale facies information can be available from two sources: 3D seismic data providing net to gross ratio (NTG) without identifying the exact location of sands and shales, or an experienced geologist drawing general trends in geological bodies in 2D which need to be reconciled in 3D modeling. We developed a procedure for Priobskoe field in Siberia, where such 2D trend maps are available. NTG is a continuous property, whereas, we needed to build a sand/shale distribution in 3D maps. We used indicator simulation in 3D to generate probability distribution of facies in 3D space. The trends for generating sand/shale distribution were either obtained from 2-D maps or geological knowledge. To match the NTG at each wells, we sampled the probability distribution in such a way that the percentage of sand and shale exactly matched with the NTG value in 2D map. The procedure can be extended to match 3D distribution within certain error limits of 2D data. Once the sand/shale distribution is created, we sample porosity values using 3D well data such that appropriate values of porosity are assigned to sands so that 2D average porosity match with 3D data. The procedure is validated in Priobskoe field and we were able to generate alternate 3-D descriptions which are conditioned to 2- D data. Introduction/Background Reservoir Modeling is a process to generate a mathematical representation of the actual reservoir. The model is built based on the available data. There are various data types that may be used for generating such model. However, the process of integrating these data is not a simple task due to several reasons such as differences in scale, resolution, quality, etc. One of the common examples is the integration of well log data with seismic attributes/maps. In this case, high vertical resolution and sparse areal distribution of well log is integrated with poor vertical resolution but good areal coverage from seismic. The integration for such process requires a good handle on the volume support from each data set. This report presents a methodology to address the above issue, i.e., to integrate 2D data into 3D reservoir model. Such methodology has been established in the literature as they are commonly used for integrating seismic data into reservoir model. In the case of seismic data integration, the exact match between the conditioning data and the estimated result after integration process may not be required. However, for the case integrating previously Approved Reserves Estimates, maps must be strictly honored by the generated geological models. The approach used for solving the problem is a geostatistical methodology which has been widely used in the petroleum industry. The method used in Geostatistics to estimate value at interwell location is known as Kriging process. The name kriging comes from Danny Krige, a South African geoscientist, who first applied this technique to gold mines. Later, the mathematical validity and foundation was provided by Matheron. This technique becomes increasing popular nowadays due to the advancement of computer technology.
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (0.45)
- North America > United States > Texas (0.28)
This reference is for an abstract only. A full paper was not submitted for this conference. Abstract Total has been strongly involved in GHG emissions reduction since several years, initially focusing on flaring reduction: all new projects since 2000 are designed with no continuous flaring and more globally, flaring will be reduced by 50% from 2004 to 2012. Second step of emissions reduction is to focus on combustion: consumptions will exceed wasted energy (flares, vent, losses) in the next years as a result of actions taken to cut by half gas flaring on one hand and evolving characteristics of assets portfolio: mature fields, LNG, extra heavy oils on the other. As part of the whole picture of Total involvement against climate change, the need to reduce energy consumption, mainly fuel gas, has led Total E&P to set up an energy efficiency action plan for affiliates and new projects. Energy efficiency assessment methodology developed with a specialized contractor is described, with a focus on 2007 pilots: Anguille field in Gabon (mature oil field under redevelopment with flaring reduction aspect) and Elgin (North Sea gas field under European legislation) in UK. Energy assessments deployment over major Total EP affiliates in 2008 is presented. The paper will show how these assessments aim at drawing a base line, defining and implementing energy efficiency plans in affiliates through listed and ranked efficiency enhancement opportunities, also at defining best practices at corporate level, and thus proposing in the near future quantified objectives of improvement. Energy efficiency assessment of affiliates not only leads to savings in energy consumptions, and reduction of emissions but also provide business opportunities through better products monetization. And in parallel to improvements on existing operations, a best in class design on new developments will ensure a global improvement of energy use in a near future.
- Europe > United Kingdom > North Sea (0.27)
- Europe > Norway > North Sea (0.27)
- Europe > Netherlands > North Sea (0.27)
- (2 more...)
This reference is for an abstract only. A full paper was not submitted for this conference. Abstract The demand for oil and gas is ever increasing. At the same time much of the new oil is in challenging environments and is increasingly becoming more difficult to produce. This, together with exponentially increasing communications capacity and computing power, has led to several initiatives in the area of Digital Oil Fields, Smart Fields C_ etc. In all these initiatives, optimization on multiple economically relevant time scales plays an important role. The downstream refining and chemicals businesses have faced similar questions and have developed a well-established hierarchy for optimization on multiple time scales (Long Term Planning, Scheduling, Real-Time Optimization, Performance Monitoring, APC, Base-layer control) in which the scope, time scales, integration, interfaces etc. have been clearly defined. There are several differences between the production system in the upstream and downstream supply chain. For example, diverse environments and workforces, significant and dynamically changing subsurface uncertainty and time scales of decades with respect to reservoir systems can characterize the upstream supply system. However, many principles of optimization and uncertainty management, such as the "division of time scales principle", are equally valid for upstream and downstream systems. This allows great opportunities to integrate and synergize upstream and downstream technologies. This paper describes how such an optimization hierarchy can be constructed for field-wide production optimization, integrating downstream and upstream concepts. This paper will propose solutions based on the above concepts, while considering business decision requirements, engineering workflows and collaborative working. It will also indicate the challenges that need to be addressed to implement and maintain such applications reliably in the oil and gas production environment. A number of concrete field cases where (part of) this principle is successfully applied will also be presented.
Abstract The lowlands area of Papua New Guinea is composed of claystone overlying a limestone formation. The upper claystone formation is primarily sticky, dispersive, and soft to very soft. Historically, drilling operations have used 12 1/4-in. steel tooth roller cone bits to drill this formation. However, one major problem with drilling this formation conventionally is the open hole time. The formation has a tendency to swell and break out, hence increasing the risk of not being able to run casing to bottom. This risk was overcome by employing casing-while-drilling (CwD). A casing drilling package comprising casing with a polycrystalline diamond compact (PDC) casing bit was used to drill the 12 1/4-in. 287-msectionin the claystone formation. The casing drilling package reached section total depth (TD) with an average rate of penetration (ROP) of 15 m/hr. The casing bit drillout was then achieved with a specific 8 1/2-in. PDC drillout bit, which then continued to section TD. By eliminating bit trips, this one-run capability of the drillout bit resulted in significant overall time savings compared with any other offset. Removal of metal cuttings while drilling out the casing bit with a PDC bit is one of the primary challenges with CwD. Rotary system drillout times with PDC bits historically have been difficult to predict, with times varying from 40 minutes to five hr. Alternatively, using a dedicated junk run with a roller cone bit can add time to the overall drilling process. In this application, a mud motor was used allowing the reactive bit torque to be monitored very closely, so that WOB adjustments could be made immediately. This resulted in an efficient drillout time of 65 minutes. Vibration damage to the specific drillout PDC bit was minimized allowing the bit to continue drilling 950 m to section TD at an average ROP of 23 m/hr, surpassing offset ROP by 44%. This paper describes the application and its challenges, and the analyses conducted to design the CwD operation. The drilling performance achieved in both the CwD and the subsequent 8 1/2-in. hole section is described and compared with that seen in conventionally drilled offset wells. Introduction Korobosea-1 was planned as a vertical exploration well in the Petroleum Prospecting Licence-240 area of Papua New Guinea (PNG). This is near the town of Mendi in the forelands area of the Papuan Basin in PNG. Typically, offset wells in this area consist of soft to very soft claystone formations to surface, overlying a thick calcareous limestone formation, which can be up to 1500 m thick. The claystone formation near surface has historically caused problems running casing to bottom. The open hole time between drilling the section and then rigging up in preparation to run casing has been planned to be as short as possible. For Korobosea-1, CwD was chosen to ensure the 9 5/8-in. surface casing was run effectively through the claystone Era beds. The vertical well was planned in three sections. The 12 1/4-in. section was to be drilled into the top of the Darai formation to approximately 300 m TVD. The 8 1/2-in. section was planned to be drilled through the Darai limestone formation until a formation change was indicated at the Upper Ieru formation at approximately 1250 m TVD. Finally, a 6-in. section was to be drilled to TD at approximately 2200 m TVD. Proposed setting depth of the PDC casing bit was 270 m.
- Oceania > Papua New Guinea (1.00)
- Europe > Norway > Norwegian Sea (0.24)
- Oceania > Papua New Guinea > Papuan Basin (0.99)
- Oceania > Papua New Guinea > PRL 269 > Darai Formation (0.99)
- Well Drilling > Drilling Operations > Running and setting casing (1.00)
- Well Drilling > Drill Bits > Bit design (1.00)