Five ways to improve onshore/ offshore planning and operations
TECHNOLOGY AT WORKFive ways to improve onshore / offshore planning and operations
The five presentations covering this range of technology offerings include: 1) a new,
field-tested technique to control the problem of sustained high pressure on the inside
casing annuli of offshore Gulf of Mexico wells; 2) use of openhole whipstocks to expedite
drilling around stuck fish; 3) review of 3-D images made during a hazards survey for a 26-mi
pipeline installation in 2,700-ft water; 4) an overview of the Sidwaste drilling waste
treating system being developed as a THERMIE project; and 5) a report by PTTC and Concurrent
Technologies on a survey of independent operators to identify industry technology needs.
 New technique controls sustained pressure problems in casing annuliNoel A. Monjure, ABB Vetco Gray Inc., Houston Sustained casing pressure (SCP), a problem in oil and gas wells for many years, can be defined as pressure inside casing annuli (other than drive or structural strings) that cannot be bled to zero nor will remain at zero after bleeding. Although SCP is well documented in many areas, it is of particular interest to operators on the OCS and the Minerals Management Service (MMS) because of concerns for worker safety and environmental protection as mandated by Congress.1 In areas of the Gulf of Mexico it regulates, MMS has developed guidelines2 for wells with SCP. These guidelines mandate zero pressure above the seafloor at all times, but do allow for certain types of non-compliant approval to maintain production or delay early abandonment. On the OCS, this waiver generally has a time limit during which the SCP problem must be monitored, eliminated or a program of improvement initiated. In recent years, this problem has become more pervasive and operators have found it necessary to spend significant capital to try to solve the problem using conventional workover rigs. To help mitigate SCP problems, ABB Vetco Gray has developed a new system for accessing restricted casing annuli where pressure is trapped and circulating heavy fluid to control the situation. SCP problem. Shell Offshore, like most oil and gas producers, has been dealing with SCP for several years, and was actively seeking solutions to eliminate it. By 1997, production engineers at Shell Offshore’s South Timbalier field had developed experience using a column of heavy fluid to displace lighter fluids present in an annulus and regain hydraulic control. Called the "lubricate and bleed" method, the process entailed attempts to pump heavy fluids through the casing valve into a closed system — the cemented casing annulus. Several pilot projects determined that fluid volumes were too small to make any significant progress. Shell Offshore approached ABB Vetco Gray for assistance, which led to the development of the casing annulus remediation system (CARS), Fig. 1.3 Challenges that faced the development team included:
A solution. CARS is a new, low-cost remedy to sustained casing pressure problems. A flexible hose is inserted through the restricted casing outlet of existing wellheads. The hose is pushed down into the uncemented portion of annuli of outer casing strings until a sufficient depth or obstruction is reached. The hose provides the needed conduit for circulation of heavy fluids and displacement of existing annular materials. This method is an improvement over the lubricate and bleed process, which did not provide a means for circulation. After reaching sufficient depth, injection of high density fluid can be performed immediately, or the hose can be permanently installed using a special valve removal (VR) plug modified to function as a terminal fitting. This arrangement allows the operator to perform multiple displacement operations without the expense of multiple service jobs. After completing R&D testing and field trials in late 1997, additional study determined that the process needed to incorporate additional equipment and procedures to deal with annuli that cannot be bled to zero, even temporarily. This study revealed that many wells would not bleed to zero, or would build up pressure quickly after shut-in. After developing new concepts and procedures to operate under a continuous pressure environment, a special 2-in., 5,000-psi manual pipe ram was built to retain and seal the flexible hose after installation. Procedures have been developed to allow operations under sustained low pressures, and new systems are being tested to allow operation under sustained pressures up to 1,000 psi. Even though all components are tested for pressure integrity and fully rated to 5,000 psi, it is recommended that the system be installed at the lowest possible pressures. This ensures personnel safety and minimizes the potential for any discharges to the environment. Operations. The process generally involves four distinct phases. In phase one, meetings are held with the operator to review available well data, casing programs and pressure history. Next, a field engineer surveys the location to verify information about wellhead installation and clearances between the subject well and nearby wells. Appropriate equipment is mobilized to the location and set up.
During the third, or installation phase, two separate groups of equipment are employed. One set is connected to the relief outlet of the annulus, and includes high-pressure lines, trash sump or cuttings box and other valves and fittings needed to safely connect the annulus to a flare or flowline. The relief outlet is used to bleed the SCP down to zero or its lowest level. The CARS assembly then is connected to the opposite outlet, if available. If the wellhead has only a single outlet, a special adapter is fitted to allow the single outlet to function as both a relief and injection outlet. This assembly includes a failsafe close, hydraulically actuated valve (which can shear the hose and shut-in the annulus if needed), a special pipe ram for the flexible hose, a packoff device (which maintains constant pressure sealing around the hose during operations) and a device to push the hose into the annulus. A number of special fittings also have been developed and tested to allow for clearance into the restricted area between the wellhead outlet and the casing, Fig. 2. After the hose has been inserted as far down into the annulus as possible, the pipe ram is closed around the hose for protection and the outer assembly is removed. The flexible hose is then prepared with the terminal fitting, and a VR tool or lubricator is used to insert the terminal fitting into the existing VR profile. This threaded profile provides a highly reliable seal along with redundant seals in both the nozzle and the terminal fitting. The final phase involves pumping heavy fluids or special sealants such as StrataLock4 to eliminate the sustained casing pressure. The operator may choose to begin displacement directly through the terminal fitting assembly, or a standard manual gate valve can be installed to allow fluid displacement at a later date. A gate valve and companion flange assembly is always installed after job completion to protect the terminal fitting from any mechanical damage.
Case Histories. The system was installed on three Shell Offshore wells in the South Timbalier Area of the Gulf of Mexico (GOM), Fig. 3. This pilot project was initiated to verify the feasibility of the mechanical installation process and fluid displacement capabilities. Installation depths ranged from 31 ft to 698 ft, as measured by a radioactive tracer in the CARS nozzle at the bottom of the string. A clear, zinc bromide brine was selected by the customer and displaced into the 10-3/4-in.´ 7-5/8-in. annulus in each well. Despite the shallow depths, initial displacement volumes ranged from 17 bbl to 43 bbl. Each installation also included the terminal fitting arrangement for follow-up injections at a later date. Displacements were significantly higher in only a few days, compared to those achieved by other methods over several years. In one well, SCP was reduced significantly and has remained so since 1997. In the second well, pressure dropped significantly after ten months, but recently it began to increase. The third well, which also had the lowest volume of heavy fluid displacement, had no significant reduction in annular pressure. The latter two wells will undergo a second round of heavy fluid injection. Following additional development in 1998, five Chevron USA wells in South Pass Area, GOM, were selected for treatment. The wells had sustained casing pressure in multiple annuli, were designed for close proximity installations in 1980 and featured only one casing outlet. A special outlet spool was designed and installed on nine annuli to allow simultaneous relief and system installation through the same outlet. Equipment was installed successfully on eight of the nine annuli. In cooperation with MMS, Chevron is developing a modified displacement procedure using progressively greater fluid densities and the monitoring of pressure reduction as the displacement is performed. SCP in three annuli in this project has been reduced significantly using the procedure. A more aggressive fluid weight should reduce SCP to zero. Following its success in these wells, and the development of new products to cover a broader section of the market, the system is being offered to Gulf of Mexico and international customers. Thus far, displacement systems have been installed on restricted annuli for casing programs such as 20-in. ´ 16-in., 13-3/8-in. ´ 9-5/8-in. and 10-3/4-in. ´ 7-in. Significantly higher volumes of fluid have been injected and displaced much faster and at lower cost, compared to previous methods. Additional installations are being planned with special sealants, such as Halliburton’s StrataLock, which should be capable of placing an impermeable barrier in the annulus to eliminate gas migration, as well as fluid flow. Preliminary field results indicate good-to-excellent success in reducing sustained casing pressure with initial displacements. Secondary injections in the remaining wells should produce further success. Acknowledgment The author thanks ABB Vetco Gray for permission to publish this article, members of the CARS development team for their tireless efforts, and Tim Wolcott with Shell Offshore Inc. and Leslie Barnes and Dave Strait with Chevron USA for their cooperation in preparing this article. Bibliography
Whipstocks: An alternative to openhole fishingAngelique R. Eubanks, BP-Amoco, Houston; Ken Brock and Rocky Seale, Smith Drilling & Completions, Houston Over the last decade, openhole fishing has been reduced or eliminated, in most cases, due to risk and economics. When problems arise in drilling operations, it is typical to limit trips in the hole to attempt fish recovery. Often it is opted to abandon the fish and sidetrack immediately. These decisions are based on overall drilling economics, taking into account total operations cost vs. cost of the tools left in the hole. In most drilling applications, the risk and economics associated with openhole fishing dictate that alternate methods be evaluated to re-establish drilling operations. Methods currently include setting a cement plug or using a whipstock to detour around the fish. Setting a cement plug has been the method of choice over the years due to risk, state of the technology and ease of installation. However, advances in cased-hole sidetracking and peripheral equipment have impacted openhole sidetracking applications greatly. Today, with new systems described here, the risk is minimal, and installation is relatively easy and usually more economical and faster than setting a cement plug. Over the past three years, a field-proven, openhole sidetracking system has been developed to give the operator additional options when drilling problems occur. By utilizing the stuck fish as the anchor for a whipstock, drilling operations can be continued. In addition to mechanical integrity, this cost-saving system has proven itself as an alternative to fishing or setting a cement plug. Consequently, the openhole whipstock system has saved money and reduced rig time during sidetrack operations. To date, two methods have been utilized for anchoring the whipstock to the fish. One uses an overshot on a slick-OD fish. The other option uses a pin connection into a corresponding box connection located on the fish. Using an overshot to anchor the whipstock assembly provides a method for selective directional control. This is accomplished with either MWD or a Universal Bottom Hole Orientation (UBHO) sub. Utilizing the screw-in whipstock system, orientation is an option when the downhole orienting swivel is run with the system. Cement plug limitations. The traditional method of setting a cement plug is generally time consuming, economically prohibitive, and often unsuccessful in sidetracking around a fish. Instances in which cement plugs may not be good alternatives to getting around a fish include: highly deviated wellbores, smaller-diameter openhole sections, deep openhole sections, high-temperature and high-pressure intervals. At deeper depths, with elevated temperatures and pressures, cement plugs rarely strengthen to more than the surrounding formation, making them difficult to use as a kickoff point. In highly deviated wells, cement plugs often get strung out along the wellbore. Without the strength of a good cement plug, sidetracking around the stuck fish is difficult. Often, numerous cement plugs will have to be set to obtain acceptable results. This is both time consuming and costly. Openhole whipstock options. Using a whipstock vs. a cement plug is a dependable and economical alternative. When a fish is left in openhole, a whipstock can be run and anchored to the fish. This provides a simple, cost-effective and positive means to sidetrack around the fish. Depending on what is left in the hole, there are different anchoring options for the openhole whipstock. If a fishing neck is looking up, an overshot may be run to latch onto the fish. With this system, the whipstock can be run with a traditional directional device, such as a UBHO sub, and oriented prior to engaging the fish. If there is inclination in the hole, orientation can be accomplished with MWD. Should a box connection be looking up, a corresponding pin connection can be run below the whipstock and screwed-in, to a desired torque. In one example application, the kickoff direction was crucial and a fishing neck was left looking up in the hole. A double-bowl overshot was run with a lefthand and a righthand grapple so that, after the fish was engaged, rotation would not be possible in either direction. On this well, the overshot was run directly below the whipstock, and the whipstock was run in the hole on a mill with a UBHO sub aligned above for directional verification, Fig. 1. Prior to reaching the fish, a wireline unit was rigged up and a surface-read-out gyro run to determine whipstock face direction. The workstring was then rotated to the right until the whipstock, face was oriented to the desired kickoff direction. The overshot was then lowered over the fish to secure the whipstock in that position. Overpull sheared the running tool from the whipstock allowing it to be pulled from the well. A milling assembly was then run to drill additional hole to accommodate the next bottomhole drilling assembly. This job was both a technical and economic success. Time and money were saved by not having to fish the bottomhole assembly. The overall operation took less time than setting a cement plug, and created the advantage of having a positive deflection around the fish. This well was the cornerstone in proving the openhole whipstock a viable option, vs. sidetracking around a fish, even when direction was critical. Screw-in whipstock system. To build on the first successful job, the tool string was altered, allowing it to anchor into a box connection downhole. In drilling operations, the drilling assembly may become stuck. A freepoint can be run to determine where the string is stuck. Once that point is determined, a connection above will be backed off, allowing the free portion of the drillstring to be retrieved. If the bottomhole assembly is to be recovered, a fishing assembly can be run. With a competent box looking up from the fish, a corresponding pin is run on the bottom of the whipstock. To withstand the makeup torque of the connection, the whipstock is run on a running tool rather than on a mill, Fig. 2. This assembly allows a high torque to be transmitted through the whipstock into the connection below, ensuring that the assembly is anchored sufficiently to sidetrack. At depth, the whipstock assembly with the pin connection down is screwed into the box connection looking up and made up to a desired torque. This is based on the connection size / type, or as operationally permitted. The whipstock running tool is then removed from the well, and a milling assembly is run to drill the rathole for the next drilling assembly. To date, there have been six jobs performed using the screw-in whipstock system in an area where setting cement plugs had a detailed history. All of these jobs were technically and economically successful. Job depths varied from 17,728 to 21,089 ft, in openhole sizes ranging from 5-7/8 to 8-1/2 in. Sidetrack distances of these six wells varied from 546 to 1,729 ft. In comparable wells in which cement plugs were used to sidetrack, operations took, on average, an additional five days and cost 40 to 76% more than the screw-in whipstock system. Screw-in system with directional control. The obvious limitation to the screw-in whipstock system is the inability to dictate sidetrack direction. With this limitation in mind, a Downhole Orienting Swivel (DOS) was developed for specific jobs in which sidetrack direction was critical. This allows the system to be screwed into the fish to the desired torque, the DOS disengaged, and the whipstock face turned to the desired kickoff direction using MWD or a UBHO sub. Once the desired direction has been reached, the DOS is locked back into place and the system rotationally locked. In March 1998, the screw-in system with orienting capabilities was run. First, the whipstock assembly, comprising pin connection on bottom, DOS and whipstock, was made up to the running tool. Above the running tool, a UBHO sub was run in alignment with the whipstock face, Fig. 3. At depth, the fish was tagged and the pin screwed into the box connection looking up. A torque of 12,500 ft-lb was placed on the system to make up the connection. With the connection made up, the whipstock face was oriented to the desired drilling direction by disengaging the DOS and reading the whipstock face with a surface-read out gyro. When the whipstock face was in alignment, the DOS was locked in place. To ensure that everything was in its proper position, 4,000 ft-lb torque was placed on the system. After disengaging the running tool, the workstring was pulled. The milling assembly was
run and 25 ft of rathole was drilled and reamed. Upon completing the rathole, the workstring
was pulled and the drilling assembly was run in the hole to continue drilling operations.
Viewing a subsea pipeline project in 3-D before constructionTo optimize construction of a 29-mi-long deepwater pipeline for Mariner Energy’s Pluto development, Oceaneering International, Inc. conducted hazard surveys and mapped the proposed route. The surveys were enhanced by use of John E. Chance & Associates’ new real-time, 3-D visualization software. Described here is an overview of the need for 3-D mapping, capabilities of the new software tool, and a summary of results of the Pluto survey. The problem. Engineers have several sources of visual information to consider when deciding the optimal route for a deepwater pipeline. Side-scan sonar mosaics — maps formed by piecing together sonar images of the proposed route — are commonly considered. However, the final composite maps are time-consuming to create, difficult to interpret and two-dimensional. ROV video images of hazards may also be factored into the decision, but the quality of these images is limited by the ROV’s range of photography, absence of light in the deepwater environment, and visibility conditions at the time of filming. The solution. Three-dimensional visualization offers an innovative alternative to traditional methods of optimal route selection for deep-sea pipelines and cables. Computer-aided design (CAD), which is used to model 3-D objects in a virtual environment, has provided the technology to model the 3-D world. While a good 2-D map is a valuable tool for any job, the advantages of 3-D are numerous; it represents the real world much better than traditional 2-D because it directly relates the X, Y, Z position of a vessel to X, Y, Z parameters of the world around it. With 3-D visualization, the subsea industry gains the ability to see clearly all elements affecting a job. In an area of poor visibility, such as the underwater environment, a virtual 3-D map is invaluable. John E. Chance & Associates’ (CHANCE) real-time, 3-D visualization software, HydroVista, is the first 3-D georeferenced mapping application to encompass real-time positioning and display. A PC-based application, it integrates and manages externally rendered objects (EROs), CAD-based maps, cameras and views. The software was specifically developed for large, multiparameter data sets, a common product of offshore surveys. When the various elements are compiled into a project, the resulting display is a systematic virtual representation of a physical subsea work site, in which dynamic objects can be positioned in real time. The software’s flexible data architecture enables users to import multi-origin geospatial data — side-scan sonar mosaics, multibeam bathymetry, sub-bottom profiler data, magnetometer records and other sensor data. Areas of steep incline, escarpments, chemosynthetic mounds, and a variety of other anomalies detected by these sensors, are modeled as digital terrain for the new software’s environment.
Natural and man-made features in the subsea construction site — such as pipelines, platforms, manifolds, shipwrecks, or any structure of known dimensions — are represented in HydroVista by objects rendered in external packages such as 3D Studio, trueSpace, and VRML (Virtual Reality Modeling Language). Position, elevation and orientation of static objects in the new software’s environment are configurable. Dynamic objects, such as working ROVs or a descending manifold, are positioned according to data from the positioning device assigned to the object. Point-to-point measuring and span analysis output in standard formats are some of the processing features that the system supports. Full integration of the technology with navigation packages in the Fugro Navigation Suite of software enables real-time, 3-D data calculations and displays, Fig. 1. Using the software’s virtual camera feature, perspectives from which the job site are viewed can be selected by placing cameras in the HydroVista environment. Cameras can be positioned in free space or attached to objects. The view from each camera is displayed in a window and can be recorded as an Audio Video Interleave (AVI) movie. The system’s movies are unique analysis / inspection tools for subsea projects. By presenting a movie of simulated construction plans, or a movie of a construction operation as it happened in real time, project details are communicated quickly and efficiently in a format that project personnel can readily comprehend. Gulf of Mexico example. Mariner Energy’s Pluto field is located in about 2,700 ft of water in all, or part of, Mississippi Canyon Blocks 673, 674, 717 and 718. Plans to develop the field include constructing a subsea tieback from two wells in MC 674 to an existing host platform in South Pass 89, to extract the estimated 25 MMbo the area holds. Connecting these sites requires laying a chemical injection umbilical, a control umbilical and 28.6 mi of 8-in. flowline. Development cost of this 3-yr project is estimated at $95 million. The innovative equipment and techniques used on Pluto establish the project as a showcase of the latest offshore technology.
Oceaneering was contracted by Mariner Energy to conduct hazard surveys and map the proposed pipeline route to Pluto. An alternate route was also to be surveyed for seafloor hazards and outcroppings. Employing the newest ship in the Oceaneering fleet, Ocean Intervention I, was the first innovation. The ship is a purpose-built, DP Class 2 (DPS2), multi-service vessel. It is designed to carry out deepwater intervention tasks in support of exploration and production activities, Fig. 2. In February 1999, Oceaneering contracted with CHANCE to provide surface and subsurface positioning services for the hazard survey. Aboard Ocean Intervention I, the Marine Construction Survey Division of CHANCE is permanently mobilized in a state-of-the-art suite from which a survey team can provide precise surface and subsea positioning service. Surface position is determined using dual-redundant Global Positioning System (GPS) receivers and Fugro’s worldwide differential correction system, Starfix, a global network of more than 80 satellite base stations. The system provides uninterrupted GPS correction data which enables the vessel to be positioned within 2-m accuracy on a 24-hr basis. For subsea positioning, two Sonardyne Long and Ultra-Short Baseline (LUSBL) systems configured for dual redundancy provide accurate acoustic positioning within 1% of the slant-measured range. CHANCE’s proprietary Starfix.NAV software is used to guide the operation. In addition to powerful data processing and display capabilities, this full-featured navigation package has the distinction of being a true GIS (geographical information system). Interfaced to the vessel’s DP system, this survey suite provides a stable platform from which to conduct subsea construction operations or typical ROV operations. Full drafting functionality is available onboard using CAD software for surveying and engineering. Ocean Intervention I departed Fourchon, Louisiana, on Feb. 7, 1999, heading to South Pass. The hazard survey was conducted over a period of two weeks. For the survey, Oceaneering deployed a Hydra Millennium 150-hp work class ROV, designed for jobs in 10,000-ft water, or more. The survey team guided the flight of the ROV along the proposed and alternate routes in water depths ranging from 420 ft to 2,730 ft. They also positioned the vessel as it performed a grid search pattern along the proposed pipeline route, searching for objects that might impede the construction process. Obstructions found during the search ranged from ladders to large boulders. When the survey was completed, data was electronically transmitted for post-job analysis and final reporting.
The post-processed package submitted to Oceaneering included deliverables from the HydroVista suite. A simulation of the proposed pipeline draped on the contoured Digital Terrain Model (DTM) of the proposed pipeline corridor was compiled in HydroVista. The DTM has been created using hazard data collected in the survey, existing hydrographic and bathymetric data, and proprietary information from the CHANCE GIS. A movie made from the new software shot along the simulated proposed pipeline in the surrounding subsurface terrain brought the Pluto project to life, Fig. 3. Despite its basis in data-derived reality, viewing a HydroVista movie of a simulated job site is truly a "through the looking glass" experience. The Pluto movie created for Mariner was no exception. "Flying" over and along the proposed pipeline, the virtual camera provides a clear view of the deep-sea terrain, formerly "terra incognito." Seafloor hazards to the deepwater lines are readily apparent, including steep slopes, gullies, canyons and other rugged topography, land slices, fluid vents, active faults and fault scarps, and naturally occurring gas hydrate accumulations on, or just below, the seafloor. Other hazards discovered in the survey — contours, magnetic anomalies, escarpments, side-scan sonar targets, chemosynthetic communities and shipwrecks — are denoted on the map by shaded areas, symbols and rendered objects. Block lines painted on the terrain and labeled with ownership information and MMS block numbers appear, as lease boundaries are approached. Viewing this movie, the topography of the route is easily visualized, as are the comparative dimensions of surroundings to the pipeline and proximity of the line to hazards. Conclusion. Accurate and cost-effective decision making is sharply influenced by how data is coordinated and presented. In the offshore industry, maps are of the utmost importance to this process. Navigation, engineering, resource management, exploration, project planning, environmental management, construction, conservation and geology are all aspects of offshore activity that rely on accurate, data-rich maps. The more information that can be compiled in a clear and concise manner, the more reliable that decision-making process becomes. As the benefits of computer-aided design were being realized in new techniques for project development, such as rapid prototyping, CHANCE recognized the potential of 3-D software technology for a comparable visual application — mapping. Mariner’s Pluto project clearly demonstrates how 3-D maps can be used to facilitate optimal pipeline route selection.
Controlled treatment of drilling wastes through a two-phase processA. Bouchelaghem and Ph. de Rochebouët, Inertec; Y. Kerbart, Pride Forasol; J. M. Hervieu, Alfa Laval; and J. Durrleu, Elf EP Environmental legislation limits the use of oil-based mud (OBM), mainly to control or prevent the discharge of oil-contaminated cuttings. The actual legislation (PARCOM) limits the hydrocarbon content associated with cuttings to 10 g/kg. These environmental criteria are not easily integrated into the economic evaluation of a well construction program. New drilling fluid systems were designed with the aim of being able to discharge cuttings to the environment, but without the environmental drawbacks attributed to oil-based mud. However, very few of these new fluids present overall properties as good as OBM, particularly in terms of wellbore stability, low fluid loss, thermal stability or lubricity. Moreover, these new drilling fluid systems remain far more expensive than conventional OBM. For these reasons, the conventional fluid is still being used. Therefore, the only way to still use OBM without polluting the environment relies on an efficient treatment of drilling wastes, i.e., mud, cuttings and associated waters. Such a system is under development, as described here. SIDWASTE project, a two-phase solution. The objective of the European Commission’s THERMIE project OB/172/96, SIDWASTE (Separation and Immobilization of Drilling Waste) — in which Inertec, Pride Forasol, Alfa Laval and ELF EP are involved — was to develop and implement a complete treatment of waste mud and cuttings during, and at the end of, the drilling process. Such a system has to be adapted to all types of drilling mud. This will position the cleaning activity as a sub-process, and associate it to a well-defined "cleaning" service fully integrated in the well construction process, including a two-phase procedure: 1) multiphase separation, and 2) immobilization of drilled cuttings. Facilities for the three steps involved in the overall treatment process are illustrated schematically in Fig. 1, Fig. 2 and Fig. 3. Multiphase separation involves isolating the different phases of waste mud — water, oil and sediment — thus leading to pure phases that can be reused or discharged and low volumes of ultimate wastes containing residual polluting materials, such as oil fixed onto the sediments. In the latter case, to be able to discharge such sediments, residual concentrations have to be lower than concentrations fixed by legislation. It is difficult to reach such low values without sophisticated equipment specifically adapted to the residual material to be treated. Immobilization involves transforming ultimate material coming from the multiphase treatment into an inert material that can be discharged without creating any environmental problem. The process immobilizes residual concentrations of polluting materials within a mineral matrix which is solid, presents a low permeability and comprises durable properties. It is more convenient to immobilize residual pollutants than to try to extract them by complex separation techniques, with a doubtful efficiency. An adaptable system. Such a configuration is interesting since it combines two complementary techniques. Thus, the multiphase separation unit has to be implemented to recover easily extracted fractions, while immobilization deals with the residual fractions fixed onto the sediments. Both techniques will be implemented in ranges in which they are the most efficient, thus leading to an optimal global yield. Another advantage of the above configuration is that it can be easily adapted to different combinations of mud and drilled formation and their respective wastes. The treatment could be integrated into any kind of rig. SIDWASTE process demonstration was done on an industrial scale during April and May 1998. All the oil-contaminated wastes produced during a drilling operation in a surburban area of Paris, France, were treated. A great amount of data, corresponding to relevant parameters, have been collected for a full technical process evaluation. The R&D phase will be finished in September of this year. Initial preliminary contacts show that this subject is of great interest to oil companies. Acknowledgment Material in this presentation appeared in the Oil & Gas Technology Newsletter, No. 23, March 1999, produced by CMPT on behalf of the European Commission.
The search for upstream technology solutionsE. Lance Cole, PTTC National Project Manager, with contributions from Rodney Sobin, Scott Cuppett, and Jim Dawson of Concurrent Technologies Corp. The upstream oil and gas business has become more adept at leveraging technologies developed or applied in other industries and adapting them to meet critical exploration and production needs. One successful example of this ability is the Natural Gas and Oil Technology Partnership (NGOTP) that operates under the U.S. Department of Energy (DOE) Office of Fossil Energy. This unique program brings together the resources of the petroleum industry and capabilities of DOE’s 10 major national labs to address research and development (R&D) needs of the upstream petroleum industry. Current and proposed NGOTP projects are prioritized each year by industry review panels and are generally long-term projects. Other federal resources work on a more short-term basis for the oil and gas industry. In both instances, the Petroleum Technology Transfer Council (PTTC) serves as the liaison with independent producers. Concurrent Technologies Corp. (CTC), an independent non-profit organization, is one such resource. Late last year, CTC sought PTTC’s assistance in identifying very specific, technology-related needs in the upstream oil and gas industry. Through a Department of Defense (DOD)-funded project, CTC is focused on commercializing "dual-use," federal-lab technologies that meet both DOD and commercial sector needs. CTC is partnered in this project with the U.S. Army Industrial Ecology Center, UNISPHERE (a technology brokering group), and the Federal Laboratory Consortium (an umbrella for the nation’s 700+ federal labs, not just those involved in the NGOTP program). Independent producers comprise one industry segment that CTC wanted to work with to identify technology needs and find potential short-term (18 months or less) federal-lab technology solutions. Surveying for technology needs. In early 1999, CTC conducted 22 telephone interviews with independent producers. Beforehand, interviewees were asked to think about "which two or three things in the technology realm, if changed, would most impact profitability." This question was separately posed in the three general areas of: exploration, drilling / completion, and field production operations, with the understanding that policy options were not part of the survey. In those interviews, producers expressed more than 94 technology needs — three-fourths of which fall within the six categories listed below (in descending order of the number of needs).
CTC evaluated the identified technology needs to determine functional and operational characteristics, as well as similarities to other technologies. Particular emphasis was placed on where military and independent producer needs overlapped. To find potential matches, CTC staff searched federal-lab Internet sites and made personal contacts. Although focusing on defense-related projects, this process naturally picked up existing DOE programs, primarily those within the NGOTP. CTC found several promising matches in the areas of: 1) saltwater / brine treatment (in ongoing NGOTP projects); 2) more efficient motors (ongoing projects in a university Advanced Energy Lab and within DOE’s Office of Industrial Technologies-Motor Challenge Program); 3) remediation of crude oil spills (EPA Remediation Technologies Screening Matrix that collects information on available commercial technologies); and 4) alternate materials to prevent or minimize equipment corrosion for the U.S. Navy, which experiences similar corrosion problems in its saltwater environment. Personally, the last observation caused a "why didn’t I think of that" reaction since my first couple of years after college I worked in a Navy R&D lab — in a materials group nonetheless. CTC kicked off its search by looking to solve the very specific needs that were expressed by a few producers. Another approach is to survey a broader audience, accepting that the responses will be less specific. PTTC did this throughout 1998 by gathering industry responses — primarily from smaller independent producers — to a survey that ranked technology topics within six categories (exploration, drilling / completion, operations / production, reservoir / development, environmental issues and information technology). Respondents indicated whether the need was ofhigh, medium or low priority. Ultimately, responses were received from more than 200 people — about 10 times the size of CTC’s interview sample. Strong interest in boosting productivity. Most "high or medium interest" responses dealt with reservoir and development concerns (as opposed to exploration) as well as operations and production issues. This is not a surprising response, knowing that independents now operate the majority of mature domestic fields. Producers are interested in technologies that will help them wring more oil and gas from mature fields, and most recognize that reservoir characterization is critical.
The independent producers that participated in the PTTC survey expressed specific interest in technologies that would help them: 1) produce more from existing wells, by identifying behind-pipe potential (includes logging advances) or through advanced stimulation; 2) prioritize in-field development through geologic targeting; and 3) increase recovery through improved oil recovery (IOR) using realistic screening criteria and benefiting from sound operating practices / guidelines, as documented in case studies. The survey responses indicated that the independents were confident in their abilities to explore for hydrocarbons in the U.S. The sole exploration topic of high interest dealt with geological play / basin analyses, reflecting that producers always need more data — a critical requirement for developing more reserves in mature fields. There is a practical reality check on these empirical findings. PTTC’s regions currently conduct over 100 workshops a year, with topics primarily selected by considering feedback from past workshop attendees and input from regional producer advisory groups. Topics chosen for workshops in the last four years do reflect producers’ needs — and, in this case, confirm PTTC’s survey results. First, operators always want more play-based workshops. Second, advanced logging has been a hot topic covered in many workshops. Third, reservoir characterization and geological modeling, which are critical to geologic targeting and IOR, are a common thread. IOR interest has not been as strong, but that is attributable to current economics and perceptions by independents that "IOR is too complicated." As America’s oil and gas producers struggle to find solid ground for their
businesses, they will need more and more answers to their exploration and production
problems. Independent producers are a diverse group whose needs can vary significantly based
on size, resources and geography, among other variables. While efforts like those described
will not address the needs of every independent oil and gas producer, they can help us focus
our often-limited resources. With broad input and focused effort, it is everyone’s hope
that we will find profitable solutions.
Copyright © 1999 World
Oil |
ecent technology
advances described here offer operators several ways to improve field operations, from the
planning of a deepwater pipeline, to improved drilling techniques, to solving a persistent
offshore production problem. And reports of an industry survey shows what technical help
independent operators are seeking. 
- Applying ultra-deep LWD resistivity technology successfully in a SAGD operation (May 2019)
- Adoption of wireless intelligent completions advances (May 2019)
- Majors double down as takeaway crunch eases (April 2019)
- What’s new in well logging and formation evaluation (April 2019)
- Qualification of a 20,000-psi subsea BOP: A collaborative approach (February 2019)
- ConocoPhillips’ Greg Leveille sees rapid trajectory of technical advancement continuing (February 2019)
