Joint Industry Project Research Articles

Jet Fires Involving Releases of Crude Oil, Gas and Water

A Joint Industry Project was undertaken to study releases representative of those that could occur on offshore installations involving well-stream fluids either at the wellhead or during processing. The project involved a programme of large-scale jet fire experiments to investigate releases involving mixtures of crude oil and gas (simulating ‘live’ crude) and water. Seven oil and gas companies and the UK Health and Safety Executive sponsored the work that was undertaken by Advantica and Shell Global Solutions at the Spadeadam Test Site, Cumbria, UK. The results demonstrate that the presence of water modifies, significantly, the size, shape, thermal characteristics and stability of a jet fire. For an equivalent release of fuel, the distance from the release point within which flame impingement could occur is slightly increased. However, the overall size of the flame, the temperatures within the flame and the overall heat loading to objects within the flame are reduced. The results also indicate that the flame is extinguished if the water content of the well-stream fluid reaches about 55% by mass. Some well-stream fluids contain a lot of water, in some cases up to 80% by mass, and these will not produce jet fires.

Well-Control Procedures for Dual Gradient Drilling as Compared to Conventional Riser Drilling

SummaryTo meet the world's increasing demand for energy, petroleum-producing companies must search for oil and gas in increasingly hostile environments. One area showing great promise is in the deepwater areas of the US Gulf of Mexico. This is evidenced by increased lease sales and drilling activity that have occurred there within the recent years. As drilling moves into deeper waters, new technologies must be developed for safe and successful operations.Around 1996, four projects were initiated to develop dual-gradient drilling (DGD) technology for use in water depths greater than 5,000 ft. The four projects are Shell Oil Co.'s project (Gonzalez 2000), the SubSea MudLift Drilling Joint Industry Project (Smith 2000) (SMD), the Deep Vision project (Sjoberg 2000), and Maurer Technology's Hollow Glass Spheres project (Maurer 2000). Several publications have discussed the advantages that DGD technology has over conventional deepwater drilling in ultradeepwaters (Gault 1996; Schubert 1999; Smith et al. 1999).Although the advantages of the dual-gradient projects are well documented, there has been little published on one of the major concerns expressed by all four projects. That is, how does well control differ for Dual-Gradient Drilling as compared to conventional riser drilling (Schubert 1999; Juvkam-Wold and Schubert 2000; Weddle and Schubert 2000)? This paper reports on a comparison of the well-control aspects of DGD to those of conventional riser drilling. It is based on the work that the authors performed as part of the SMD project.

Pipe/Soil Interaction Behavior During Lateral Buckling

This paper addresses lateral pipe/soil interaction behavior at the large displacements that occur with lateral buckling of a pipeline. Force-displacement-response models were developed by the Safe-buck joint-industry project (JIP) to replace the use of simple friction-coefficient approximations. Such simplistic models are unrealistic for modeling large lateral displacements or the building of soil berms that occurs with cyclic lateral loading. The models are based on large- and small-scale tests carried out by the Safebuck JIP on deepwater soils from the Gulf of Mexico and west Africa, as well as on kaolin clay. To this database was added project-specific test data donated by JIP participants. Four stages of pipe/soil interaction are considered: Embedment of the pipe at installation. Breakout during buckle formation on the basis of different levels of initial pipe embedment. Large-amplitude lateral displacement as the buckle forms. Cyclic lateral displacement influenced by the building of soil berms. While breakout loads have been the subject of much research and published papers on pipeline stability, there is little guidance on modeling lateral resistance at the large displacements experienced in lateral buckling. There is also little guidance on modeling subsequent large-amplitude cyclic behavior, which occurs with each shutdown and restart of the pipeline. New equations were proposed where appropriate, and recommended models for each part of the characteristic response were developed. These models provide a valuable basis for lateral-buckling design guidance. They currently are being applied by JIP participants on a number of projects in which pipelines are being designed for lateral buckling. Background of the Safebuck JIP The aim of the Safebuck JIP (Bruton et al. 2005) is to raise confidence in the lateral-buckling-design approach and to improve understanding of the related phenomenon of pipeline walking. Experimental work is being undertaken at the Welding Inst. on low-cycle fatigue-materials performance and at Cambridge U. on axial- and lateral-pipe/soil interaction. The JIP has been very well supported by the offshore industry. BP, ConocoPhillips, ExxonMobil, Petrobras, and Shell, as well as the U.S. Government through the Minerals Management Services, participated in Phase I, with installation contractors and suppliers represented by Allseas, JFE-Metal One, Technip, and Tenaris. Additional participants including Acergy, Chevron, Statoil, and Saipem have joined Phase II, which will run through 2005 and 2006.

Flashing liquid jets and two-phase droplet dispersion: II. Comparison and validation of droplet size and rainout formulations

Loss of containment often results in flashing releases of hazardous chemicals into the atmosphere. Rainout of these chemicals reduces airborne concentrations, but can also lead to extended cloud duration because of re-evaporation of the rained-out liquid. Therefore, for hazard assessment one must use models which accurately predict both the amount of rainout and its rate of re-evaporation. However, the findings of a literature survey reveal weaknesses in the state-of-the-art for modelling the sub-processes of droplet atomisation, atmospheric expansion, two-phase dispersion, rainout, pool formation and re-evaporation. A recent joint industry project has implemented recommendations from this survey, deriving from scaled water experiments droplet size correlations for conditions ranging from negative to high superheat. This experimental programme is reported in more detail in a separate companion paper. As a whole these correlations describe a tri-linear function of droplet size (expressed as Sauter mean diameter) as a function of superheat. This function describes the regimes of non-flashing, the transition between non-flashing and flashing, and fully flashing. The new correlations have been compared with previous correlations recommended by the Dutch Yellow Book and CCPS Books. The correlations are validated against published experiments including the STEP experiments (flashing propane jets), experiments by the Von Karman Institute (flashing R134-A jets), and water and butane experiments carried out by Ecole des Mines and INERIS. The rainout calculations by the dispersion model have been validated against a subset of the CCPS experiments (flashing jets of water, CFC-11, chlorine, cyclohexane, monomethylamine).

VASPS Prototype in Marimba Field - Workover and Restart

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 95039, "VASPS Prototype in Marimba Field - Workover and Restart," by G.A. Peixoto, G.A.S. Ribeiro, P.R.A. Barros, and M.A. Meira, Petrobras, and T.M. Barbosa, UENF/LENEP, prepared for the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, 20-23 June. The vertical annular separation and pumping system (VASPS) represents an innovative concept for subsea gas/oil separation and pumping. A prototype was installed in 2001 in the Marimba field in the Campos basin. The full-length paper presents the second operational phase of the prototype after a successful rig intervention to change a damaged electrical submersible pump (ESP). Introduction The VASPS is a gas/liquid-separation system associated with an ESP. After the gas/liquid mixture is separated by passing through a helical channel, the liquid phase is pumped by the ESP, and the gas is vented to the platform. This subsea phase separation reduces the bottomhole pressure required for a given production rate, thus increasing production from an individual well. A joint-industry project (JIP) involving AGIP, ExxonMobil, and Petrobras developed the VASPS prototype installed inside dummy Well MA-23 to separate the production from Well MA-01 and produce to the semisubmersible platform P-08. The VASPS prototype operated as expected from July until December 2001, when a failure occurred in the ESP system. Because the failure was related to the control system and not to any of the technology challenges of the project, the JIP partners decided that the technology was successful and ended prototype testing. After this, Petrobras assumed the technical and financial responsibilities to return the system to operation. Between the failure in December 2001 and the beginning of 2004, Well MA-01 continued production to P-08 by bypassing the VASPS unit. In January 2004, a rig intervention replaced the ESP. The VASPS prototype resumed operation in May 2004. Several changes were made in the control system to improve reliability. The full-length paper details the workover process, improvements to the control and supervisory system, and system performance after the intervention. VASPS Components Fig. 1 shows the main components of the VASPS. The supervisory and control system comprises a hydraulic-power unit, a subsea control module (SCM), a master control system, a subsea choke, and two level sensors. The electrical system includes the ESP connected to the liquid-discharge tube, downhole sensor, power cable, wet-mateable connectors, and variable-speed drive (VSD) on the P-08. Initial Operation Phase In July 2001, Well MA-01 was producing 750 m3/d of fluid with 100 000 m3/d of gas from gas lift. Wellhead pressure was 36 kg/cm2. After VASPS installation, the subsea phase separation allowed the wellhead pressure to be reduced to 11 kg/cm2. This resulted in a production increase of 1000 m3/d without gas lift. After 5 months operation, the VASPS prototype failed because the ESP control and production systems did not act as expected after a process-plant incident.

High-Mode-Number Vortex-Induced-Vibration Field Experiments

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17383, "High-Mode-Number Vortex-Induced-Vibration Field Experiments," by J.K. Vandiver, Massachusetts Inst. Of Technology; H. Marcollo, AMOG Consulting; and S. Swithenbank and V. Jhingran, Massachusetts Inst. of Technology, prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May. This paper presents the initial results from vortex-induced-vibration (VIV) field testing of a long, flexible, model riser at a high mode number. The experiments were designed to gain understanding of the dynamic behavior of a long riser in uniform flow responding at mode numbers ranging from 10 to 25 in crossflow vibration. The observed reduced velocity and root-mean-square (RMS) displacement-response levels were reported. Mean values of the drag coefficient, Cd, and hydrodynamic damping derived from measured data were compared with calculated values from formulas commonly used in engineering design of offshore systems. Introduction Experiments at Lake Seneca, New York, took place in the summer of 2004. They were part of a larger testing program developed by Deepstar (a joint-industry technology-development project) for improving the ability to model and mitigate VIV. While these particular tests were focused on investigating uniform-flow conditions, a second set of tests designed for shear-flow conditions was performed subsequently in November 2004 and will be reported separately. The initial motivation for this field experiment was to improve the under-standing of VIV at high mode numbers. Most model testing has been conducted at low mode numbers (<10). Drilling and production in 1000- to 3000-m depths requires understanding VIV behavior at higher mode numbers but still short of infinite-length behavior. Experiment Description The Lake Seneca test facility is a fully equipped field-test station moored in calm, deep water. It was ideal for conducting a controlled test on a long, circular pipe in uniform flow. As Fig. 1 shows, the tests were accomplished by towing a vertical, composite pipe with a suspended bottom weight to produce the desired tension. The length, diameter, and tension of the pipe were chosen to permit crossflow excitation of up to the 25th mode. The maxi-mum speed possible with the system was limited by the maximum allowable deflection angle of the pipe. Typical towing speeds were approximately 0.3 to 1.1 m/s. The pipe was constructed in 30.5-m-long segments, which were joined together. Total pipe length was limited to 137 m by the depth of Lake Seneca. During the experiment, total lengths of 61.26 and 122.23 m were tested. Each 30.5-m-long section of pipe contained six evenly spaced triaxial accelerometers. The sampling rate was 60 Hz per accelerometer. The same serial network was used to sample the tension- and tilt-measuring devices very close to the top U-joint, connection. Two mechanical current meters measured towing speed; one was suspended underneath the towed weight, and the other hung over the side of the towing vessel. A load cell and tiltmeter were attached at the top of the pipe. This instrumentation allowed measuring the tension in the pipe and the top angle of inclination.

Fatigue design of plated structures using finite element analysis

Finite element analysis is being used by designers for fatigue assessment of structures. It is therefore important that a proper link between calculated hot spot stress and fatigue capacity is established, and that guidance on such analysis is included in design standards. This paper presents a summary of the finite element analyses performed for assessment of hot spot stress with link to one hot spot S–N curve in the FPSO Fatigue Capacity Joint Industry Project. Recommendations are presented on how to perform fatigue assessment of plated structures based on finite element analysis combined with one hot spot S–N curve.

Pulse echo CHIME as a tool for non-intrusive inspection of pressure equipment

Non-Intrusive Inspection (Nil) offers a number of benefits over traditional Internal Visual Inspection (IVI) approaches for pressure equipment. Nil is being used increasingly in a range of industries and there is a need for inspection techniques that can rapidly cover large areas yet provide good inspection performance. The CHIME technique. originally developed by AEA Technology for the HOIS Joint Industry Project, is emerging as a highly effective tool thai successfully meets a number of Nil needs. This paper provides background to how Nil planning defines the performance requirements for inspection techniques and identifies those situations for which pulse echo CHIME providers the best integrity management solution. The principles of operation of pulse echo CHIME are deserved. along with some recent developments that have enhanced its capability. Practical application of pulse echo CHIME in NII is discussed and some examples of recent applications in major NII programmes are provided.

The Continuous-Circulation System: An Advance in Constant-Pressure Drilling

Summary In late July 2003, for the first time since rotary drilling was introduced, a section of hole was drilled without interrupting circulation while new joints of drillpipe were added to the drillstring. This was made possible by the use of the continuous-circulation system (CCS), developed over the previous 3 years by a joint industry project (JIP) that was managed by Maris Intl. and funded by six major oil companies (Shell U.K., BP, Statoil, BG, Total, and Eni),Coupler Development Ltd., and Varco, and supported by the U.K.'s Industry Technology Facilitator. The field trial of the CCS was carried out on a land well being drilled in Oklahoma, U.S.A. Its success marked the end of the JIP and the commencement of commercial development of the system. The CCS is a new and enabling technology; the potential benefits of which include the following: Elimination of negative and positive pressure surges when stopping and starting circulation to make a connection. No rig downtime to circulate out cuttings to clear the bottomhole assembly before making a connection. Improved drilling-fluid management. Elimination of kicks on connections. Improved control of equivalent circulation density (ECD). Reduced total connection time (TCT). Reduced chance of stuck pipe during a connection. No downtime in high-pressure/high-temperature (HP/HT) wells to circulate out connection gas. Reduced wellbore "breathing" or "ballooning." Improved safety around the rig floor. Potential applications of the system include the following: Extended-reach drilling (ERD) and horizontal wells. HP/HT wells. Near or underbalance wells. Deepwater wells. The CCS is also a potential-enabling technology in achieving the "one-tripwell."1 The concept was presented in a paper by inventor L. Ayling at the Offshore Technology Conference, May 2002.2

Fatigue Capacity of FPSO Structures

This paper presents an overview of a joint industry project, addressing the problem of fatigue capacity of FPSOs (FPSO=ship shaped structures used for floating production storage and offshore loading). Spectral methods are becoming standard methodology for fatigue assessments of FPSOs. This methodology is well suited to numerical methods in combination with finite element representation of the global structure and structural details for response analyses. A proper link between calculated stress and fatigue capacity is required in order to achieve a reliable design. The project has generated significant amounts of numerical data as well as laboratory fatigue test data of typical ship details to improve the design basis for this. An overview of this project together with some links to the main results and recommendations from this project will be presented in this paper.

State of the Art of Ultradeepwater Production Technologies

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 17615, "State of the Art of Ultra Deepwater Production Technologies," by J.M. Bell, SPE, Chevron; Y.D. Chin, SPE, Aker Kv ærner; and S. Hanrahan, SPE, Chevron, prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May. The full-length paper summarizes some results of several recent joint industry projects (JIPs) on ultradeepwater field-development technologies. A review of emerging and existing technologies for deepwater development is presented, which would be of particular interest to technology-development personnel and asset-team personnel who are in the appraisal or concept-selection stages of a project. Introduction As offshore production moves from deep water (3,000 to 6,000 ft) to ultradeep water (6,000 to 10,000 ft) and moves farther away from infrastructures, many existing technologies reach their limits or must be improved. Several successful JIPs have demonstrated that in the high-expense and -risk environment of ultradeep water, structured collaboration aligned with business drivers is a successful formula for delivering the technologies required to meet the ultradeepwater challenge. The demand for critical technology and engineering systems to enable production from ultradeep water has triggered breakthroughs in many conventional technologies. The full-length paper focuses on sub-sea, flow-assurance, floating-production-system, and riser technology.

Overview: Coiled-Tubing Applications (June 2005)

Having been involved in coiled-tubing (CT) technology for many more years than I care to admit, it is interesting to see how much has changed during the last quarter century. Improvements in CT manufacturing, materials, equipment design, and computerized monitoring, as well as a better understanding of CT mechanics, set the stage for rapid growth and acceptance of CT as a viable and versatile oilfield tool. I firmly believe that, following this initial technology surge, the advent of various knowledge-/experience-sharing conferences and joint-industry projects, focused solely on CT technology and needs, have accelerated this CT “revolution.” The first technology-transfer gatherings I recall attending were the HydraRig-sponsored forums beginning in 1989 through the World Oil CT conferences beginning in 1993. There also were several other public and intercompany events offering forums for CT pundits during the 1990s. In 1996, recognizing the need to share ideas on a larger scale, the Intl. Coiled Tubing Assn. (ICoTA) introduced its roundtable conferences. ICoTA soon teamed with SPE to bring us what is now considered the premier CT technology-transfer forum. This year, estimated attendance at the 2005 SPE/ICoTA Coiled Tubing Conference and Exhibition was 880—up 100 from last year—not including an additional 57 Texas A&M U. students we “graying” technologists were happy to welcome. As I was reviewing papers from recent SPE and SPE/ICoTA conferences for this month’s feature on CT technology, it became apparent to me just how much the focus of the CT conference papers has changed. It seems to me that most early-conference papers centered around CT mechanics—on why CT behaves the way it does and predicting when it will break—and around successful CT jobs for any number of applications. Recent offerings focus more on mainstream issues and what I call CT exploitation. - Reducing the cost and extending the market for CT drilling services. - Improving operational and safety efficiency. - Discussing successful CT programs. - Delivering solutions to complex problems in areas lacking economically viable alternatives. And, of course, there still are the ubiquitous novel and unique thought-provoking sub-jects the innovative CT community is known for. Additional Coiled-Tubing Applications Technical Papers Available at the SPE eLibrary: www.spe.org SPE 92513 Underbalanced Coiled-Tubing Drilling: Update on a Successful Campaign SPE 94058 Some New Developments Applicable to Coiled Tubulars SPE 94159 World’s First Utilization of Coiled Tubing to Dissolve Hydrate(s) in an FPSO Riser: Case History SPE 94102 An Effective Sweep-Cleaning of Large Deviated Wellbores Using Small Coiled-Tubing Systems SPE 90558 Effect of Coiled-Tubing Curvature on Friction-Pressure Loss of Newtonian and Non-Newtonian Fluids—Experimental and Simulation Study

Paleozoic Carbonates of the Commonwealth Of Independent States (CIS): Subsurface Reservoirs and Outcrop Analogs: SEPM Special Publication No. 74

William G. Zempolich and Harry E. Cook, Editors, 2002, SEPM, Tulsa, 245 p. (SEPM members; US $75.00; nonmembers; US $100.00) ISBN: 1-56576-083-2. This volume is an outgrowth of an SEPM Research Symposium held at the 1997 AAPG-SEPM Annual meeting in Dallas, Texas. The papers in this volume reflect new research as well as reviews of previous work and represent some of the first joint industry and academic projects since opening of the Commonwealth of Independent States (CIS) to outside study. As the editors point out, the studies in the volume will be a first glimpse of CIS carbonate strata for many western scientists. The area of focus in this volume is important on several fronts. For one, it contains some of the world's largest oil and gas provinces in terms of known petroleum volumes. Also, nearby spectacular outcrops serve as analogs to the reservoirs. Finally, the Paleozoic carbonates of the CIS include many of the world stratotype locations, and the thick succession of Paleozoic carbonates preserved there provide insight on the various factors influencing the evolution of platforms through time and their diagenesis. With all of these aspects considered, the volume is billed as having appeal to geologists interested in petroleum aspects of the region, those with academic interests, and anyone interested in carbonate sedimentology in general, and specifically in Paleozoic carbonate sedimentology and stratigraphy. The volume consists of a brief introductory paper by the editors followed by nine papers, an index, and four loose foldout plates tied to two of the papers. The introductory paper sets the stage for the volume, including the importance of reservoirs in the area, and then briefly summarizes key aspects of each paper. The following paper by Kuznetsov is an overview of Paleozoic reef building in Russia and surrounding regions. There are four major …

Best practice for the assessment of defects in pipelines – gouges and dents

Oil and gas transmission pipelines have a good safety record and are a demonstrably safe means of transporting hydrocarbons. This is due to a combination of good design, materials and operating practices. However, like any engineering structure, pipelines do occasionally fail. The major causes of pipeline failures around the world are external interference and corrosion; therefore, assessment methods are needed to determine the severity of such defects when they are detected in pipelines. Defects occurring during the fabrication of a pipeline are usually assessed against recognised and proven quality control (workmanship) limits. These workmanship limits are somewhat arbitrary, but they have been proven over time. However, a pipeline will invariably contain larger defects at some stage during its life, and these will require a ‘fitness-for-purpose’ assessment to determine whether or not to repair the pipeline. Consequently, the past 40 years have seen a large number of full scale tests of defects in pipelines, and the development of a number of methods for assessing the significance of defects. Some of these methods have been incorporated into industry guidance, others are to be found in the published literature. However, there is no definitive guidance that draws together all of the assessment techniques, or assesses each method against the published test data, or recommends best practice in their application. To address this industry need, a Joint Industry Project has developed a pipeline defect assessment manual (PDAM). PDAM documents the best available techniques currently available for the assessment of pipeline defects (such as corrosion, dents, gouges, welding defects, etc.) in a simple and easy-to-use manual, and gives guidance in their use. PDAM is based on an extensive critical review of pipeline fitness-for-purpose methods and published test data. It is intended to be another tool to help pipeline engineers maintain the high level of pipeline safety. In addition to identifying the best methods, PDAM has served to identify a number of limitations in the current understanding of the behaviour of defects in pipelines, and the empirical limits in the application of existing methods. This paper discusses the PDAM project, in the context of both the current best practice available for defect assessment and the limitations of current knowledge.

Cased-Hole Completions Without Perforating Eliminate Risks

Perforating is a double-edged sword for well completions in unconsolidated formations. Perforations open conduits for hydrocarbon flow from the formation to the wellbore. But the perforating process can cause damage to the formation and result in excessive debris, posing operational risk and impairment to well productivity. As a result of a joint industry project (JIP) formed in 2002, a new technology has been developed and field tested that installs a liner and sand control completion in a single trip while eliminating explosive perforation charges and associated risks. The Enterprise One-Trip Sand Control/Liner Hanger Completion system was developed by a JIP that included three major operators, a large service provider, and a small technology company. The fact that the technology was taken from concept to successful field-installation readiness in just 22 months illustrates that when operators and service/technology providers are committed to a common goal, technology uptake in the E&P business can proceed quickly. Perforating Risk Factors Perforating poses operational risks for operators in unconsolidated formations. Additionally, the perforating process can jeopardize well productivity by reducing the area open to flow and damaging the formation. Generally, well productivity is directly related to the area of flow through a perforation tunnel. The greater the area of flow, the greater the well productivity. Entry-hole diameter and shot density impact flow area. Perforation debris in the perforation tunnel can block the available flow area, as can fractured and compacted zones and broken pieces of formation. The flow restriction caused by crushed zonal rock can also increase skin values, particularly over the life of the well.

The Disc Bit - A Tool for Hard-Rock Drilling

SummaryThis paper traces the development of a radically different design of drill bit, describing its concept, laboratory work, and the latest field trials.Disc-bit technology is based on the single-rolling disc cutter. This cutter was first used successfully in rock on a tunnel-boring machine in 1956. By the early 1970s, virtually every rock-tunneling machine in the world had evolved from picks, tungsten carbide button cones, or multirow tapered cutters to the single-row disc. By then, practical field experience had demonstrated the superior performance of tunneling machines. Further, the Colorado School of Mines (CSM) began scientific studies and published data comparing the specific energy of excavation of various tools on the basis of full-scale laboratory testing. These studies clearly showed that the single-row disc cutter required less energy than conventional cutters used in roller cones to excavate a given volume of rock. With energy at the cutting face always a limited commodity, a lower energy requirement translated to a higher rate of penetration (ROP).Not until the mid-1990s was the concept of the single-rolling disc cutter applied to drill bits. Very small—3¼-in. Mini-Disc™— cutters were evaluated at CSM and found to be extremely efficient and sufficiently robust to be used on drill bits as small as 7⅞ in. An evaluation of an 8½-in. disc bit was performed at the Gas Research Inst. (GRI) Catoosa Test Facility in Oklahoma. The U.S. GRI sponsored an effort to develop the concept through laboratory and field testing. Other field trials were sponsored by private and government grants, including the most recent test funded by a joint industry project (JIP) and managed by Petrobras.

Workover Strategies in CHOPS Wells

Abstract The most fruitful area for continued OPEX (Operating Expense) reductions in CHOPS (Cold Heavy Oil Production with Sand) operations now appears to be well workovers to solve mechanical and reservoir problems, and to improve production rates. Workovers (exclusive of water-blocking methods) were the subject of a one-day workshop organized by the Lloydminster and District Heavy Oil Section of the Petroleum Society in Lloydminster, March 15, 2000. Approximately 35 attendees participated in a wide-ranging discussion of various workover methods. Participants discussed well problems requiring workovers, and evaluated technologies for re-establishing production under various conditions. Attendees represented companies and agencies such as Petrovera, Husky, ExxonMobil, Anadarko, Nexen, the Alberta Research Council, and the Universities of Waterloo (Ontario) and Alberta (Edmonton). The full information package that was developed for the workshop may be accessed at the website http://www.lloydminsterheavyoil.com/completionscience.htm. Development and assessment of workover techniques is a "work-in-progress"; these charts and slides are designed only as a guide to technical advances and to workover assessment. We feel strongly that the time has come for a joint industry project on the economic assessment of various workover approaches to optimize workover planning. Introduction CHOPS (Cold Heavy Oil Production with Sand) has been successfully implemented in many Canadian heavy oil fields (Figure 1), ranging in viscosity from 300 to 55,000 cP. CHOPS involves massive continuous sand influx, from <0.5﹪/vol to as high as 10﹪/vol during the steady-state phase of oil production. This sand influx, and the necessity to maintain it to sustain economical oil production, generates an unusual set of operational demands and operators are gradually developing better production methods, waste disposal methods, and workover methods. A typical CHOPS well produces 5 - 25 m3/d (30 - 150 bbl/day) of oil, and, for a good well in viscous oil, perhaps as much as 500 - 800 tonnes of sand in a year. Most CHOPS wells now use progressing cavity pumps with surface drives, as these give good oil rates while handing large sand volumes and eliminating rod fall problems. Workovers are required during the life of a well to change r repair equipment, and to maintain or re-initiate sand and fluid influx. The basic operational goal in the petroleum industry is to produce maximum oil with minimum OPEX over an optimal time to maximize netback. In the period between 1990 - 1998, the heavy oil industry in the Lloydminster area reduced OPEX in CHOPS wells from about $75/m3 to $44/m3 ($12.00/bbl to $7.00/bbl). This was achieved in large part through conversion to progressing cavity pumps, but also because of many micro-engineering advances in handling and disposing of sand, in developing better workover equipment and methods, and in refining details of well design. FIGURE 1: Canadian heavy oil deposits. Available in Full Paper. Currently, over 100,000 m3/d (600,000 bbl/d) of heavy oil are produced in Canada using CHOPS technology, comprising over 20﹪ of total Canadian oil production. This production level could easily be doubled in 24 months if the upgrading capacity in North America were expanded accordingly.

Equilibrium-equivalent structural stress approach to fatigue analysis of a rectangular hollow section joint

The equilibrium-equivalent structural stress method has been recently developed through several joint industry projects as a robust method to analyze welded components using finite element methods. This method has been proven effective in correlating a large amount of published fatigue test results in the literature. The authors employed this equilibrium-equivalent structural stress method for a competition organized by the SAE Fatigue Design & Evaluation (FD&E) Committee to predict the fatigue life of a rectangular hollow section joint. Among all the methods used by many participants, the authors’ life prediction was selected as the best, based on the actual test results. This paper provides the details of the SAE FD&E fatigue challenge problem definition, test results, and our structural stress approach. The predicted mean life by the equilibrium-equivalent structural stress method utilizing the proposed ASME Div. II Structural Stress curve was in excellent agreement with the actual mean life of the experimental results. Other stress indexes (such as the maximum principal stress and the von Mises stress) had maximum stress at a location different from the actual crack location. Furthermore, the equilibrium-equivalent structural stress showed significant mesh tolerance with only a few percent difference in stresses when halving the mesh size.

Energy absorbing passive impact barrier for profiled blastwalls

After the Piper Alpha accident, the Health and Safety Executive (UK) now require safety cases to be submitted for all new and existing installations on offshore topsides. The findings from a recent Joint Industry Project have revealed that peak overpressures developed from typical hydrocarbon explosions can be much higher than previously used in the design of offshore topsides and thus has necessitated strengthening of many existing installations, including blastwalls. This paper presents one such technique where the response of the blastwalls is modified by the inclusion of a passive impact barrier system placed at a certain offset behind the walls. An explicit non-linear finite element model has been validated against two large scale blast tests of shallow profiled blastwalls. This has included modelling the effect of contact, weld tearing, large displacement and plasticity in order to provide a realistic model. The study has been extended to investigate the response of deep profiled blastwalls with various arrangements of the passive impact barrier systems. The increase in the containment pressure and the influence of strain rate, load duration, offset of the impact barriers and its stiffness are discussed.

The effect of dents in pipelines—guidance in the pipeline defect assessment manual

The pipeline defect assessment manual (PDAM) project is a joint industry project, sponsored by sixteen international oil and gas companies, to produce a document specifying the ‘best’ methods for assessing defects in pipelines. A dent reduces the static and cyclic strength of a pipe. Plain dents, dents on welds and dents containing defects are considered here; small scale and full scale tests, theoretical analyses and assessment methods are discussed, and the ‘best’ methods included in PDAM are described.