Wireline Operations Research Articles

Technology Focus: Reservoir Surveillance (September 2023)

The energy transition and global geopolitical situation present numerous oil and gas operators with opportunities to accelerate production growth and monetize hydrocarbon resources. While rapid production growth comes with proportional risks, it becomes crucial for reservoir surveillance engineers to quickly identify, derisk, and mitigate subsurface performance uncertainties. In this demanding scenario, the need for high-frequency reservoir performance surveillance is more critical than ever. Fortunately, advanced technologies have emerged as a refuge for subsurface engineers facing these challenges. One such technology is fiber optics, which has matured significantly over the past two decades, allowing for real-time well-performance overviews in various applications. This capability enhances well-management efficiency and enables prompt corrective actions, as demonstrated in papers SPE 200088 and SPE 200806. Along similar lines, the dynamic nature of the industry has also driven subsurface practitioners to think innovatively and apply existing technologies for out-of-the-box solutions. For instance, tracers, traditionally used for understanding subsurface connectivity, are now being used to calibrate surface networks and optimize gas lift injection performance. Such unconventional approaches have been explored in paper SPE 207431, highlighting their effectiveness. In addition to tracers, technologists are turning rock cuttings, often considered mere waste, into valuable information. As demonstrated by paper SPE 206214, these insights aid in elucidating depositional sequences and fluid-migration paths, thereby facilitating better field development decisions. Furthermore, technology groups are working on innovative solutions that use advanced sensing and artificial-intelligence (AI) -based technologies. As a result, interventionless downhole pressure and temperature surveying are no longer distant dreams (paper IPTC 22255). In another example, the power of AI has elevated sensing intuition, optimizing reservoir and fluid characterizing operations and leading to improved drilling-cost efficiency and the quality of well delivery (paper SPE 210091). Embracing advanced technologies is vital for oil and gas operators to optimize production, reduce risks, and make informed decisions in the evolving energy landscape. From real-time fiber optic monitoring to unconventional tracer applications and AI-driven solutions, reservoir surveillance engineers now have an array of tools at their disposal to drive the industry toward a more efficient and sustainable future. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200806 An Industry Overview of Downhole Monitoring Using Distributed Temperature Sensing: Fundamentals and 2 Decades Deployment in Oil and Gas Industries by Mohammad Soroush, RGL Reservoir Management, et al. SPE 206214 Reservoir Architecture and Fluid Connectivity in an Abu Dhabi Oil Accumulation by Erik Tegelaar, Triple EEE, et al. IPTC 22255 Sensor Ball: Field Deployment of Autonomous and Untethered Surveillance by Mohamed Larbi Zeghlache, Saudi Aramco, et al. SPE 211543 The Sensor Ball Revolutionizes Wireline Operations by Nasser M. Al-Hajri, Saudi Aramco, et al.

Tutorial: A Century of Sidewall Coring Evolution and Challenges, From Shallow Land to Deep Water

Due to the high cost of conventional coring operations, rotary sidewall coring has become increasingly important, particularly for deepwater operations. The rig costs, operational challenges, and amount of time involved to core wells below 30,000 ft are considerable, even for wireline operations. As wells get deeper, formation pressures will exceed 30,000 psi, and differential pressures can exceed 10,000 psi, which will eclipse the capabilities of traditional rotary coring tools. New technology has been introduced to enhance the recovery of rotary sidewall cores to improve operations and capabilities on these challenging wells that will be the primary subject of this paper. This new technology can also enhance coring operations and reliability for land and other offshore operations, in addition to deep water. New improvements and challenges include: * Reliable 1.5-in.-diameter core samples, with a 35,000-psi-rated tool * New high-powered coring tools with enhanced energy to address cutting Lower Tertiary wellcemented formations (Wilcox, Lower Miocene, etc.) * Higher torque and horsepower at the bit to enhance cutting and prevent stalling when coring * High-powered surface systems along with highstrength and high-power wireline cables * Upgrades to address high temperatures, highdifferential pressures, high-mud viscosity, large (24 in.) boreholes, and improved reliability * New drill bits and catcher rings to use a high-power system and operate in harsh coring environments * New cutting, retrieval, and core handling advancements for reliability in hard, consolidated formations * Combinability upgrades to reduce wireline trips and reduce rig costs for coring * Dual-coring tools with the ability to have different catcher rings and bits downhole simultaneously on a single run, along with tool redundancy downhole for improved reliability * Combination of rotary coring and formation sampling operations to obtain formation pressures, fluid samples, and rotary sidewall cores on a single run * Downhole monitoring of the coring operation, which includes drilling functions like torque, bit force, penetration rate, core bit penetration, and recovered core length, along with tool orientation * Core recovery information to enable 100% core verification downhole, so extra cores are not cut unnecessarily during the job, with individual core plugs measured and verified downhole * A unique method to seal the cores in a pressurecompensated coring tube downhole to capture all the formation fluids in the rock in downhole conditions * Complete rotary coring downhole operations can be monitored remotely for offsite interaction during the coring operation Besides reviewing historical coring tools and techniques, new technology is also discussed in more detail. The new technology starts with the introduction of the 1.5-in.-diameter rotary sidewall coring tools for deep water over a decade ago. Many applications and technologies are presented to show their effectiveness for deepwater operations. The successful examples include acquiring 1.5-in. cores in large boreholes, hard formations, deep wells, high-differential pressures, and extreme hydrostatic pressure. There are also examples of new technology available for future operations, including dual coring, combination coring, and sealed pressurized coring.

Coiled Tubing Sets Packers Precisely During Offshore Well Abandonment

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29839, “Successful Offshore Coiled-Tubing Permanent Well-Abandonment Operation Uses Downhole Real-Time Parameters To Set Inflatable Packers With Surgical Precision in Cost-Effective Manner,” by Cassiano Guimaraes, Eduardo Delgado, SPE, and Lucio Galvao, Halliburton, et al., prepared for the 2019 Offshore Technology Conference Brasil, Rio de Janeiro, 29-31 October. The paper has not been peer reviewed. Copyright 2019 Offshore Technology Conference. Reproduced by permission. The complete paper discusses the systematic approach adopted by a service company to achieve the goal of safely abandoning wells offshore southwest Brazil with different completion types using light workover vessels. Having determined the abandonment methodology, service company personnel developed processes and procedures to reach the objective that included advances in coiled-tubing (CT) rigup procedures and use of a real-time telemetry system. Introduction The use of a CT real-time telemetry sys-tem enables accurate setting of a through-tubing inflatable device system (T-TIDS) by monitoring the necessary downhole parameters in real time. The paper presents a case study wherein sensors [such as a casing collar locator (CCL) to perform depth correlation before setting the T-TIDS and placing cement plugs, a pressure sensor to monitor the T-TIDS setting, and a CT internal pressure sensor to help ensure all cement was pumped out of the CT] were used in real time to verify that well barriers were set in place, contributing to successful well abandonment. Real-time data collection proved to be the most-effective methodology for running critical equipment, thereby saving overall time and cost. General Abandonment Requirements The decision for permanent abandonment of a well is not always easy. In Brazil, the National Agency of Petroleum, Natural Gas, and Biofuels (ANP) has established a compendium of rules for oil companies that extract and produce oil, gas, and derivatives. This involves a group of barriers known as CSB, which is a set of one or more elements with the objective of preventing the unintentional flow of fluids from the formation to the external environment and between intervals in the well considering all possible paths. The CSB’s aim is to guarantee the isolation of intervals with current and future flow potential. Cement or other material with similar performance must be used as barrier elements. Achieving a unique solution is dependent on having up-to-date information regarding the wellbore diagram, reservoir, history, well location, CT-performance capability, surface equipment, well-control equipment, and proposed layout. Fig. 1 illustrates the design of the 3D wellbore graph generated with modeling software. Solution Described The well discussed in this work contains deposits of asphaltene and sand-accumulation debris. For the operator to perform a plug-and-abandon (P&A) intervention, an effective solution to provide reliability safely is necessary to avoid worsening the well condition and delaying the intervention. The service company offered experienced personnel and engineering capabilities, a customized program for job-specific requirements, the CT package, and reliable processes and advantages compared with heavy workover units. Included as part of those advantages is a variety of bottomhole-assembly (BHA) tools that can be deployed in the well with the capability to be customized, working together with wireline operations and the robust management safety system.

Solution for the Repair of Holes in Production Tubing Without Rig and Without Wireline Operations

Summary The objective of this paper is to present the development and application of a tool to repair holes in oilwell production tubing, using a method that does not require rig and wireline operations to locate the depth of the hole. The tool locates the leak and repairs it in a single run, reducing the time required to re-establish well production. This article describes the operational mechanism of the tool and its installation process. Two repairs were performed in oil wells, one of which sealed a hole near the bottom of the tubing and the second of which sealed a hole near the surface. The holes were sealed in a fraction of the time required by current solutions. This newly developed tool is a cost-effective alternative for resolving oilwell-integrity problems.

Sampling While Drilling: An Emerging Technology

Summary Even though it is the early days of the realization of sampling-while-drilling (SWD) as a service, a picture of what might be achievable in practice is beginning to emerge. Previous SWD experience has demonstrated that the sampling process may be controlled sufficiently well that relatively clean samples may be acquired when sampling aquifers drilled with water-based muds (WBMs), and it has demonstrated that the SWD tool and sensors used are capable of operating effectively while withstanding the drilling process. On the basis of this experience, operational guidelines have been formulated, particularly regarding the most opportune time to sample during the drilling process. The first part of the paper describes SWD in a high-angle appraisal well drilled to assess the continuity and quality of several target sands and to establish the degree of continuity of these sands with the main field. The well was drilled by use of an oil-based mud (OBM). Samples would be acquired after the well had reached total depth so that the most appropriate sampling points could be identified by means of openhole logs. Multiple water-, oil-, and gas-bearing formations were identified. Sampling duties were split between the SWD tool and a drillpipe-conveyed wireline sampling (WLS) tool in an attempt to rationalize the sampling program of the well. To enable a comparison of the relative performance of the two tools, two oil-sampling stations were chosen where multiple samples would be acquired under similar operating conditions by both tools. In addition, water samples were collected at two stations by the SWD tool and scanning was performed at one (wet) gas station to confirm the formation-fluid type. Laboratory analysis of the oil samples at the common stations showed that the contaminations and fluid properties of the samples acquired by the two sampling tools were very similar. The second part of this paper describes results obtained in an appraisal well and sidetrack in a different field. Both pilot and sidetrack were high-angle wells drilled by use of OBMs. The purpose of these wells was to identify and evaluate the commercial potential of unproduced hydrocarbon-bearing zones. Both wells were drilled to total depth before conducting sampling operations, and no wireline operations were planned in either well. Five oil samples were acquired in the pilot well in two zones, and four oil samples and two water samples were recovered in the sidetrack. The results obtained during the SWD operations described suggest that it is possible to consistently acquire quality formation-fluid samples during drilling operations, even under less-than-optimal sampling conditions and strict time-on-station constraints. The quality of the samples recovered is sufficient to perform reliable pressure/volume/temperature (PVT) analyses.

The human performance model for complex and safety critical operations - a case study on drilling and wireline operations from the North Sea

The Petroleum Safety Authority, Norway has performed projects and audits related to human factors and the drillers’ and the wireline operators’ work situation. The purpose of this paper is to present the human performance model in drilling and wireline operations based on the experience and what was learnt from projects and audits. The human performance model is an analysis of what is involved in human performance. Human performance can be predicted but it requires an understanding of the human, the activity being performed, and the context in which it is performed. The paper presents specific challenges in a sensitive work environment that have a large potential to pose some serious threats to the health, safety integrity, and work performance efficiency.

Building a Well-Control Culture

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IADC/SPE 112736, "Building a Well Control Culture With WellCAP," by S.M. Kropla, IADC; O.A. Kelly, SPE, T. Gillis, and P. Sonnemann, Chevron; J.J. Metcalf, SPE, Newfield Exploration; O.L.A. Santos, SPE, Petrobras; and R. Rodrigues, Transocean, originally prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed. The development of competent personnel capable of recognizing, avoiding, and mitigating well-control situations requires industry-developed systems capable of establishing necessary training standards and quality-assurance programs that monitor training-provider performance, both essential elements for ensuring proper skills development through fit-for-purpose training. The well-control accreditation program (WellCAP) operated by the International Association of Drilling Contractors (IADC) is designed to provide the drilling industry with the building blocks for a comprehensive "well-control culture" beginning at the floor-hand level and continuing to the most-seasoned drilling personnel. Introduction WellCAP was the first industry-developed training standard and training-provider accreditation program for drilling well control. When implemented in the mid-1990s, it broke new ground with a "core curriculum" for well-control training along with procedures and criteria for evaluating multiple facets of the operations of a training provider, from facilities and equipment to testing practices and instructor qualifications. It also introduced a new role for IADC as a group charged with monitoring and auditing training-provider performance to ensure adherence to its standards. Since the original implementation, these elements have evolved continuously to improve training effectiveness and the strength of the program. Originally released with only a core curriculum for drilling, the program now also addresses workover and completion; coiled tubing (CT), snubbing, and wireline operations; underbalanced operations; and managed-pressure drilling. The system has been accepted by operators, contractors, and service companies, and it has been adopted as the internal standard for major oil companies and drilling contractors. Nearly 90 training providers currently are accredited by IADC, with more than 125,000 WellCAP certificates issued since the program started (in recent years, the program has averaged more than 25,000 certificates per year). Instruction currently is given in 12 languages. Program Evolution The curriculum offerings have evolved steadily since the program was first implemented in 1995. Originally released with only a core curriculum for drilling, workover and completion were added in 1997. Basic well servicing was addressed with the development of curriculum for CT, snubbing, and wireline operations in 2001. Also that year, IADC developed the industry's only well-control curriculum for underbalanced operations. While the number of levels of instruction and types of curriculum available to providers may seem daunting, the system is designed to allow both commercial providers and in-house training departments the ability to tailor their training to best meet the needs of their customers or organizations.

Should the FCC Depart from More than a Decade of Market-Oriented Spectrum Policy? Reply to Skrzypacz and Wilson

In this report, we reply to the comments of Andzeg Skrzypacz and Robert Wilson on behalf of Frontline Wireless in the Federal Communications Commission's 700 MHz Auction proceeding. Frontline's economists primarily advocate two restrictions on the auction that would significantly limit the number of bidders for the E Block license, one of several blocks for sale in the auction. One restriction would exclude all incumbent wireless operators and cable operators from participating in the E Block auction. A second restriction would require that the winning bidder employ a wholesale-only business model. We examine the likely costs and benefits of these two restrictions in some detail. We argue that the benefits of these restrictions would likely fall short of the costs, so they should not be adopted. In performing our cost-benefit analysis, we point out that Skrzypacz and Wilson failed to consider the unintended consequences of recent efforts to restrict entry in U.S. wireless auctions (the NextWave story) and to impose mandatory open access obligations on U.S. wireline operators (the CLEC story). To justify their first restriction, Frontline's economists assert that the only motivation for the incumbents' participation in the E Block would be to foreclose other wireless entrants. We explain that there are procompetitive reasons for the incumbent carriers to participate in the E Block auction. We also explain that Frontline's economists have failed to demonstrate that incumbent carriers have both the ability and incentive to warehouse spectrum. To justify their second restriction, Frontline's economists assert that the wireless industry's market structure is inefficient due to vertical integration of incumbent carriers across wholesale and retail functions. According to Skrzypacz and Wilson, Frontline's proposed wholesale-only restriction would permit the wireless industry to evolve into an allegedly more efficient state of structural separation, as incumbent carriers would be forced to embrace a wholesale business model. We demonstrate that the authors fail to present a compelling case as to why their proposed business model would likely result in benefits in excess of costs. We explain that the proposed restrictions on the auction would likely insulate firms, such as Frontline, from competition in the auction. Such insulation may result in a windfall for Frontline, but it is unlikely to be in the best interests of the American consumer. The FCC should send a clear signal to industry participants that it rejects any form of rent-seeking behavior by rejecting Frontline's proposal.

Improved Operations With a High-Efficiency Jackup

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 105883, "Improvements in Operations Using a High-Efficiency Jackup," by Gordon Hart and Allan Ramsing, Mærsk Contractors, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20–22 February. A high-efficiency ultra large jackup rig was used in operations offshore Norway for ConocoPhillips at the Ekofisk field. The rig uses "x-y" cantilever skidding, and it is rigged with a quadruple der-rick with dual standbuilding capability and space for casing racking. Background The Marine Structure Consultants CJ-70 type jackup drilling rig Mærsk Innovator is drilling development wells on the Ekofisk 2/4M platform for ConocoPhillips Norway. The rig is to drill 25 of 30 planned wells over a 3- to 4-year period. The other five wells were drilled with the Mærsk Gallant. The wells are a mixture of deviated (up to 80° inclination) and horizontal wells. The program with the Innovator commenced in late November 2005. First, 10 conductor strings were drilled and set. Second, a cuttings-reinjection well was drilled and completed to allow self-sufficient operation in cuttings handling. The final step is drilling and completing the wells. As of November 2006, eight producing wells had been drilled and completed. A further program of batch-setting eight conductor strings was completed during the summer. Design In addition to operational performance, these rigs were designed with features to improve safety and environmental performance.Decks clear of ventilators and crane pedestals—allows use of a forklift truck for container handling.Automated pipe-handling system.Enclosed moonpool.Fully enclosed large-capacity mud pits.Automated mud-mixing and solids-control systems.Dual engine rooms—allows maintenance in "quiet" room.Zero-discharge system.Quiet-zone accommodations.Driller's cabin comprising three ergonomically designed workstations. Increased efficiency was the result of the following.Dual pipe-handling equipment: racking machines and iron roughnecks (two each servicing the well center and the foxhole).Remotely operated pipe-handling machine for transferring tubulars from the cantilever to the drill floor.Casing run in stands.The derrick designed for fourbles of Range-II or thribbles of Range-III drillpipe, resulting in 25% fewer connections.Variable deckload with a capacity in excess of 10 000 tonnes.Three large-capacity cranes with redundancy to cover deck areas.Large deck space and storage capacities for all equipment and consumables.Cuttings-handling and slurrification systems.Slurry-injection system.Proprietory x-y cantilever-skidding systemMoonpool area with capacity to run coiled-tubing or wireline operations offline through a secondary moonpool. Performance Of the 54 wells used in the database, the Gallant drilled 11, a Mærsk giant-class rig drilled four, and the remainder was drilled with platform drilling. For the purposes of this comparison, only the Gallant performance was considered.

The rollout guys [telecommunications systems integrators

The author, who has been involved in seven major European installations, describes what systems integrators do for an operator. Systems integrators are an essential part of the telecommunications ecosystem. Both wireline and wireless operators, as well as large corporations, often rely heavily on these players in their efforts to increase capacity, deploy new services or upgrade their infrastructure. So it is not surprising that the variety of skills required by systems integrators is comprehensive. The areas that must be as, or even more, familiar to the system integrator as they are to the carriers themselves include: field and systems engineering; the provision of service analysis; network configuration; RF optimisation; overall resource management. In order to oversee such projects competently, systems integrators and field engineering companies need to be able to manage global operations round the clock. They must be able to guarantee rapid fault resolution for any site in the world to minimise downtime of any network element. The article describes the priorities of the systems integrator.

Observations on the Current Canadian Ownership Debate in Telecommunications

We assess the economic harms that would accrue if Canada were to adopt asymmetric rules of foreign ownership for incumbent carriers and entrants. We begin by reviewing the U.S. attempt to stimulate competition in local telecommunications markets through an analogous form of asymmetrical regulation. Despite the best of intentions, United States regulators have not been able to stimulate meaningful local competition through such asymmetrical regulation. Moreover, the resultant easy access to capital created wasteful investment by the entrants. Second, licensing restrictions on foreign carriers in the U.S. reflects another form of asymmetric regulation because they apply only to wireless licenses, not wireline operations. This licensing process confers substantial discretionary authority on the FCC, which has allowed the process to become highly politicized. Finally, asymmetric rules for broadband services have cemented the position of cable modem providers vis-a-vis DSL providers. The U.S. experience highlights several issues that may be relevant for Industry Canada as it assesses the effect of changes in foreign ownership rules on competition in telecommunications. In particular, the investment of more than $40 billion by entrants in the U.S. local telecommunications markets has been almost completely squandered. This asymmetric regulation did not succeed in attracting entrants that would have a measurable effect on the retail price of telecommunications services. Given the nature of demand for and supply of telecommunications services, competition is more likely to develop across different platforms - cable, wireline, and wireless - not among small niche players lured into the marketplace by regulators. With the lessons of the U.S. regulatory experience in mind, we review two specific Canadian proposals regarding foreign investment rules: tiering and licensing. We conclude that a tiering approach would harm competition and infrastructure investment because it would reduce the incentives of incumbent carriers to invest in network upgrades or new services and potentially aggravate the problem of excess capacity that plagues the telecommunications industry. A licensing approach for foreign investment restrictions should also be rejected. Licensing would impose a further layer of regulation on the marketplace, reduce foreign investment, and expose foreign carriers to political pressures. The Canadian agencies should not follow their southern neighbors down the road to despair.

Improved Depth Control For Slickline Increases Efficiency In Wireline Services

Abstract The continuing quest for cost reduction in the oil field has required operators to take a closer look at all areas that might compromise efficiency. One area that has been identified is depth measurement accuracy. In addition to the critical part it, plays in service operations, depth measurement accuracy plays a significant role in the success of new completion concepts. A new measurement system has been developed that increases the, efficiency of wireline operations by improving measurement inaccuracy experienced with traditional measurement systems. Conventional methods for depth measurement have employed mechanical measurement devices without capability to make measurement adjustments for environmental or physical stress factors; therefore, these systems have not provided absolute accuracy. Through incorporation of a newly developed electronic counter that can provide continuous high-speed depth adjustment and data transmission, the new system can make the necessary adjustments for more accurate, depth control. From testing and case histories, the practical benefits and enhanced capabilities of electronic depth measurement include:Depth-measurement accuracy for ail commonly used Slick-lines and braided lines.Measurement corrections for stretch resulting from line tension and temperature effects on counter heel.Microprocessing compatible with slickline speeds.Retrieval of depth, line speed, line tension, and, time data for downhole memory production surveys and wire management programs.Use of the system for downhole, memory tool surveys as, a "cost-effective alternative to electric2line logging.Use of the system to facilitate nippleless completions. High speed resolution and data retrieval make this system inherently more efficient for support of slickline well servicing and other operations in which depth-control accuracy is critical to operational success. Introduction The volatility of oil prices has forced operators to focus more heavily on reduction of drilling and completion costs. Mechanical wireline or slickline services have provided a cost-effective means for routine well maintenance and workover for years. However, an increase in the scope of slickline services has recently been noted. One of the significant factors to this increase has been the development of a new measurement system that better supports industry needs for accurate depth control in servicing operations. Until economic constraints caused a resurgence of investigation into enhanced efficiency strategies, very little attention had been given to slickline depth measurement and the technical merit of surface measurement accuracy during normal operations. FIGURE 1: Wireline tools. Illustrations available in full paper. Slickline servicing provides an effective means for performing well maintenance by high speed mechanical manipulation of downhole service tools. Services such as setting packers and bridge plugs, perforating, and running downhole memory surveys can be accomplished with slickline at substantial savings over comparable electric line services. Accurate depth measurements are important to the efficiency of these operations and in some cases, are critical to the life of the well. For example, locating holes in tubing for deploying tubing patches, running memory tool surveys where depth correlations are necessary to well performance evaluation, setting flow devices or bridge plugs, and locating depth of lost tools during "fishing" jo FIGURE 2: Typical rig-up. Illustrations available in full paper.

Safety Initiatives Enhance Integrity of Offshore Platform Operations

Summary Following an in-house survey team's review of Exxon Co. U.S.A.'s offshore operations in the Gulf of Mexico, the Offshore Div. Risk Evaluation and Control (RECON) team initiated a number of upgrade programs directed at preventing an accident potentially resulting in injury, damage, or pollution; providing effective response if an accident should occur; and providing for safe and timely platform abandonment if the accident escalates beyond control. This paper describes the gulfwide procedural and equipment enhancements undertaken to address these three areas of personnel safety. Enhancement Program Objectives The RECON team, formed in Oct. 1989, addressed issues involved in the enhancement of personnel safety at offshore platforms. The team divided its efforts into three basic categories: accident prevention, response/control, and platform abandonment. To reduce the probability of an incident (fire or hydrocarbon release), a number of procedural issues were addressed and modified. Simultaneous-operations procedures were rewritten and expanded, and training was provided to enhance employee understanding. Safety-systems operating guidelines were revised to communicate management expectations more effectively, to introduce control procedures, and to minimize the bypassing of safety devices. Equipment lockout/tag-out guidelines also were expanded to underscore the importance of this maintenance requirement. The frequency and level of investigation regarding emergency shutdown testing were increased to levels appropriate to ensure operation in a real emergency. Pipeline riser inspection and protection were enhanced. Additionally, a releasable fusible device was developed to allow closure of wellhead surface safety valves (SSV's) in a situation without fire when they are locked open during wireline operations. Several emergency response issues were addressed. Emergency response training involving scenario drills was developed, conducted, and implemented. Platform firewater systems were upgraded, and fire response training was enhanced. Alarm, communications, and emergency lighting systems were upgraded and expanded. Orientation of personnel regarding emergency procedures and equipment was improved through the development of site-specific orientation brochures and tours, as well as the production of a new orientation video for first-time visitors.

Measurement And Correlation Of Asphaltene Precipitation From Heavy Oils By Gas Injection

Abstract The nature of asphaltenes and their role in the production and processing of crude oils has been the topic of numerous studies. This is due to the fact that the economics of oil production can be seriously affected by the asphaltene deposition problem. This paper presents a novel method to visualize in situ asphaltene precipitation from heavy oils with light hydrocarbon gases, e.g. methane. propane, ethane/propane mixtures, and carbon dioxide at reservoir pressures and temperatures. Experimental results are reported for the effects of temperature (up to 100 °C), pressure (up to 20 MPa) and composition on the formation of asphaltene precipitates from heavy crude oils. A series of titration experiments were conducted with several n-alkanes to determine the amount of asphaltenes precipitated. Both the amount and nature of the precipitate varied with the solvent used. Propane was the most prolific of all the solvents used in precipitating asphaltenes from the heavy oils. A thermodynamic model proposed by Hirshberg et al. was used to correlate the experimental data. Introduction Miscible and immiscible flooding of crude oil reservoirs by light hydrocarbon gases, carbon dioxide and other injection gases has become a popular method for enhanced oil recovery(1). The flooding process, however, causes a number of changes in the flow and phase behaviour of the reservoir fluids and can significantly alter rock properties. Such changes include the precipitation of asphaltenes(2) and wettability reversal which can alter recovery efficiencies. The existence of asphaltenes in crude oils and their deposition inside reservoirs and wellbores can cause severe problems and affect the efficiency and cost of petroleum production. The important parameters that affect asphaltene precipitation during gas injection are the compositions of the crude oil and the solvent gas, and the pressure and temperature of the reservoir(3–5). Precipitation of asphaltenes is a complex process and it is generally followed by flocculation which produces an insoluble material in the heavy oi1(6). Asphaltenes are believed to be stabilized in solution by resins and aromatics and the asphaltene/resin ratio plays a key role in their precipitation. This ratio is more important than the absolute asphaltene content in determining which crudes will be subject to precipitation. Problems arising from asphaltene deposition have been reported in the literarure(7,8) for many field projects. Some examples of these are the Ventura field in California(9), Hassi Messaoud field in Algeria(l0) and heavy oil fields in Venezuela(l1). Deposition of asphaltenes in the wellbore can be a serious production problem and may require frequent solvent washings and scrapings to maintain oil production(10). Significant damage can be caused during well acidizing because the acid can cause the asphaltenes to precipitate and form rigid films. Other problems associated with asphaltene precipitation are the seizure of downhole safety valves submersible pumps, hinderance in wireline operations and production restrictions. These problems are discussed in derail by Leontaritist(7). Presently asphaltenes are removed either by mechanical cleaning, chemical cleaning, or by manipulating reservoir conditions (for example, pressure, production rates, etc,)(10,12). The approach taken by the oil industry has been a remedial one.

Simultaneous Wireline Operations From a Floating Rig With a Subsea Lubricator

Summary In 1987, an extensive wireline program was completed on two subsea wells in the Highlander field in the central North Sea with a subsea lubricator deployed from a drilling rig that was drilling and working over adjacent wells. Working on two wells concurrently is a way to reduce the operating costs of a subsea development significantly.

Casing Deformation in Ekofisk

Casing deformation resulting from reservoir compaction occurred in the Ekofisk field operated by Phillips Petroleum Co. Norway and is a serious problem in three of the fields. This study established a relationship between reservoir compaction and casing failure by statistical analyses, finite-element modeling (FEM), and the analyses of deformed casing and logs run through collapsed casings. Ekofisk casing deformation is related primarily to the near well incremental strain, well inclination, and casing diameter. Useful correlations to estimate future probabilities of casing deformation as a function of reservoir variables and well parameters were also obtained. The authors concluded that casing failure induced by reservoir compaction can be minimized through a pressure-maintenance program to reduce strain by drilling with the highest practical angle and by using the largest possible casing in the well.

An Operational Subsea Wireline System

This paper describes an operational subsea wireline system that is self-contained and flexible and offers a safe, economical, and proven method for riserless re-entry into any subsea well. The system discussed here was developed over a number of years and has been used to carry out a comprehensive range of wireline tasks from floating vessels in the North Sea. Although generally deployed from a diving support vessel (DSV), the system has been successfully used from a drilling rig to conduct wireline operations in a well, simultaneously with workover operations in an adjacent well, on a subsea template.

Extending VSP to Three-Dimensional MWD: Using Drill Bit as Downhole Seismic Source: ABSTRACT

Vertical seismic profiling (VSP) has been used over the past decade to provide seismic images near well bore. A new well bore seismic technique, the TOMEX/reg sign/ Survey, uses the natural vibrations created by the drill bit during the drilling of a well as a downhole energy source. Since the TOMEX Survey requires no downhole instrumentation, it eliminates lost rig time and avoids the complications of open-hole wireline operations. These factors are important whenever rig time is expensive or the risk associated with open-hole operations are high. Furthermore, the ease with which surface receivers can be deployed makes multioffset surveys much more cost effective than conventional offset VSP.

Subsurface Safety Valves: Safety Asset or Safety Liability?

Summary This paper summarizes the methods used to compare the risk of a blowout for a well completion with a subsurface safety valve (SSSV) to a completion without an SSSV. These methods, which could be applied to any field, include a combination of SSSV reliability and conventional risk analyses. The Kuparuk River Unit Working-Interest Owners recently formed a group to examine the risks associated with installing and maintaining SSSV's in the Kuparuk field. Considering Kuparuk field operating conditions, the group was charged with determining whether SSSV's are a safety asset or whether the numerous operating and maintenance procedures make them a safety liability. The results indicate that, for the Kuparuk River Unit, an SSSV becomes a safety liability when the mean time between SSSV failures is less than 1 year. Because current SSSV mean time to failure (MTTF) at Kuparuk is approximately 1,000 days, they are considered a safety asset Introduction The use of SSSV's in onshore North Slope development wells was adopted as a statutory requirement to prevent oil spills caused by casing collapse in a permafrost environment. The primary reason for installing an SSSV in a well completion is to reduce the risk of a blowout, an uncontrolled flow of well fluid to the environment. However, a number of wireline and workover operations specifically conducted to service SSSV's in an individual well are likely. These operations, in turn, represent additional risk of a blowout. A typical risk analysis was used to compare risk with and without SSSV'S. The steps of the analysis are as follows.Define the equipment system, in this case the two alternative well completions to be studied.Develop the possible failure modes that could affect the reliability of the system.Build a fault tree to describe these failure relations.Develop component failure rates for each branch of the fault tree, including the development of the relationship of SSSV availability to the other components of the fault tree.Calculate the total failure probability as a function of SSSV MTTF. Not all the component failure rates were derived easily because of the nature of the data required. Thus some of the failure rates are based on engineering judgment. This does not affect greatly the comparison of two very similar well completions, because the relative failure rate is more important than the absolute failure rate. When a component failure rate appeared to have significant influence on the results a range of values was used in the calculation. System Definition The standard production well completion for the Kuparuk field (Fig. 1) has a tubing-retrievable subsurface safety valve (TRSSSV) installed at approximately 2,000 ft [610 m] measured depth below the surface. In the rare event of a TRSSSV failure, the first repair method is by wireline manipulation. If this is unsuccessful, the TRSSSV is locked in the open position, and a wireline-retrievable subsurface safety valve (WRSSSV) is used as an insert inside the TRSSSV. If the WRSSSV fails, it can be retrieved and replaced by wireline operations. If the failed WRSSSV cannot be retrieved or repaired, however, a workover is required. A workover is required also in the event of a leak in the subsurface hydraulic control line. These Kuparuk field operational procedures were analyzed and used to develop the well-system model under study. System Failure Modes To analyze the completion reliability, the possible failure mechanisms were identified. These included completion equipment failure, operational failures, and several catastrophic events, such as drilling-rig derrick collapse, plane crash, and vehicle collision into wellheads. Certain plane crash, and vehicle collision into wellheads. Certain risks that could not be quantified-such as acts of war, acts of sabotage, and acts of God (earthquakes, etc.) were omitted from the study. Fault Tree Development The application of fault-tree risk analysis to well completion systems is well documented by Woodward. The reliability of a component or system of components is the probability that it will perform its functions for a specified probability that it will perform its functions for a specified time interval and is predicted generally by a single-parameter exponential distribution: (1) where R(t) is the probability the component will operate without failure for time period t under the stated operating conditions. JPT p. 1813

Development of Fire-Resistant Wellhead and Christmas Tree Equipment

Summary Sarawak Shell Berhad (SSB) has adopted the philosophy that wellhead equipment for platforms and other congested high-risk areas should be designed to withstand a fire in a neighboring well. This paper outlines the considerations leading to the development of the fire-resistant wellhead and Christmas tree and describes the weaknesses inherent in standard wellhead equipment exposed to fire. Introduction The need for fire-resistant wellhead equipment became apparent in the early 1970's after a multiwell fire that resulted in the loss of an offshore platform. Later investigations showed that the fire started with a blowout in one well, but before it could be controlled, the fire caused neighboring wellheads to fail and their wells to blow. A thorough examination of wellhead equipment recovered after the fire provided ample data about the damage a fire can cause.1. Wellheads with exposed flanges will not contain well fluids, and all exposed parts will be destroyed rapidly.2. Large metal masses act as a heat sink and withstand fire far better than thin, exposed items.3. The surface safety valve (SSV), if located on a wing valve, will fail quickly. (Six SSV's located on the flowline wing did not close because of excessive friction or were reopened by repressuring or failing debris.)4. A large external force may cause the clamp and the wellhead components to come apart as the bolts on the clamps come loose or fail.5. All external surfaces and pans of the overhead may be exposed to temperatures greater than 1100 degrees C [1832 degrees F], however, the larger internal sections are subject to lower temperatures, about 450 degrees C [842 degrees F]. Although the seal material in valves and in the tubing and casing hangers apparently did not leak, severe charring occurred. This made it difficult to conclude that the standard valves and tubing hangers were always reliable in fire conditions. As discussed later, further development work on behalf of SSB has included developing fire-resistant valves and fire-resistant tubing hanger neck seals. Fire Testing of Equipment Following the study of wellhead equipment recovered after the blowout. a series of tests was conducted to investigate the performance of flanges, clamps, and SSV's under fire conditions. The tests confirmed that.1. Flanges are prone to early failure under fire conditions.2. A shield with insulation material will protect a flange in a fire adequately for several hours.3. Large clamps do not experience extensive damage when subjected to a gas fire.4. Fire tests of several surface safety actuators showed that they will operate and close in a fire. Recommendations for Improved Fire Resistance As a result of the fire tests, it was possible to recognize design shortcomings in the standard wellhead equipment and to develop the first generation of fire-resistant wellheads. These are available from most manufacturers and generally have the following features.1. A forged integral block contains two master valves, a side outlet, and a swab valve for each tubing string. These multivalve components reduce installation cost and result in a stronger, more compact wellhead, which, because of its mass. acts as a heat sink and withstands fire far better. The disadvantages are that some flexibility is lost and replacement is more difficult and costly.2. The surface safety valve is on the top master valve. Moving the actuator from the wing to the top master valve was a basic change. Such a location is more positive in well control. The top master valve is far more positive in well control. The top master valve is far more likely to stay intact during a fire than a wing valve; and, in addition, there are fewer flanges that must contain well pressure. Also, the well can be remotely shut in if loss of wellhead integrity occurs in the top portion of the tree, or if the lubricator leaks or is knocked off. One disadvantage is that there is danger of accidentally cutting a wireline with this location of the surface safety valve. Thus, a reliable, fail-safe lockout device must be used or some other procedure followed during wireline operations.3. Any flange connection upstream of the surface safety valve (physically below it) subject to well pressure is either eliminated or protected by an insulated shield.4. The Christmas tree is designed to eliminate all small exposed parts.5. The outlet valves on the tubing spool utilize a studded connection. JPT P. 89