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North America
Abstract Tar sands are a combination of sand, clay, water and bitumen. In-situ techniques using steam and/or solvents are used to reduce the bitumen viscosity such that it can be recovered and refined into petroleum products. Steam-assisted gravity drainage (SAGD) is an increasingly common technique which involves drilling two horizontal wells into the tar sand deposits. Steam and hot water are injected into the upper well to reduce the viscosity of the bitumen, which will drain into the lower well where it can be pumped to the surface. The waste generated from drilling these wells is extracted from the drilling fluid by shakers and includes sand contaminated with bitumen and drilling fluid. Treatment of this waste stream is challenging and typically these sands are stored at the rig site or transported for disposal at centralized sites. This paper presents novel technology for treatment of the tar sands drilling waste generated from SAGD and other tar sands drilling operations. The continuous treatment process is based on hot water addition, mixing and separation techniques to reduce the viscosity and specific gravity of the bitumen to separate it from the sand. Treatment of cuttings with light to heavy bitumen contamination and varying quantities of fine sand and clay particles has shown this treatment method to be a simple and effective means of producing clean sand and recovering the bitumen component. The energy used to heat the circulating water is recycled to minimize waste and maximize energy efficiency. The cleaned sand can be blended with natural soil and safely disposed in the environment. The recovered bitumen can be used as feedstock for further processing and refining. With the total recoverable tar sand reserves in Canada and Venezuela estimated at 300 billion barrels, the market demand for this technology is potentially immense. Effective treatment of the tar sands cuttings will convert the waste into a valuable revenue stream in an environmentally responsible manner. Introduction Tar sands are naturally-occurring sandstone formations saturated with bitumen or heavy oil. The sandstone is thought to remain water-wet in the formation and can be unconsolidated, with the sand grains held together mainly by the bitumen. Alternatively the sandstone can be consolidated with silica or carbonate cement holding the sand together and bitumen filling the remaining voids. The bitumen deposits were formed in the geological past from crude oil which migrated to the surface of the earth. Weathering, chemical and biological processes resulted in loss of the light fractions leaving behind the very viscous, solid or semi-solid heavy fractions. Typically bitumen has a density greater than 960 kg/mC; light crude oil, by comparison, has a density as low as 793 kg/m. Over the millennia, weather and geologic action covered the semi-solid bitumen with layers of soil and other matter and today, most bitumen and heavy oil production comes from deposits buried more than 400 meters below the surface of the earth. Bitumen deposits are found in over 70 countries worldwide, but 75% occur in Canada and Venezuela. In Canada, most of the oil sands are located in three major areas in Northern Alberta: the Athabasca-Wabiskaw oil sands; the Cold Lake deposits; and the Peace River deposits, which between them hold at least 175 billion barrels of recoverable bitumen. In Venezuela, the Orinoco tar sands contain 180 billion barrels of extra heavy crude oil. Where the heavy oil is thin it can simply be pumped out of the sands using progressive cavity pumps.. The Venezuelan deposits have a typical viscosity of <20,000 cP at the reservoir temperature (61 to 95ยฐF; 16 to 35ยฐC) and can be recovered in this manner. To increase recovery, cold heavy oil production with sand (CHOPS) is also used where sand is encouraged to enter the well by aggressive perforation and swabbing strategies. Removal of the sand with the heavy oil increases the formation permeability, grows the high-permeability zone as sand is produced and prevents plugging of the near -wellbore due to asphaltenes or fines.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.94)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.35)
- North America > United States > Louisiana > Standard Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Cold Lake Oil Sands Project > Clearwater Formation (0.98)
Abstract High accuracy, speed, and a low false alarm rate are critical to the success of event detection systems and the reduction of non-productive time (NPT) due to unplanned events. The balance between them has been difficult to achieve; however, the application of a probabilistic approach with the use of Bayesian methods has shown significant promise. The results of a research prototype for kick detection using such methods were described in a previous paper (Hargeaves, Jardine, Jeffryes, 2001). The improvements in automated signal processing technology and increased computer power have meant that these new approaches to large scale data analysis in real time are now more widely possible. This paper describes the extension of this work to develop a rig-based quick event detection (QED) system for mitigating a number of common drilling risks, including kicks, circulation loss, and drillstring washout detection. The QED software application runs on a standard standalone PC at the wellsite and continuously calculates the probability that an event is occurring. The probability changes as an event occurs, which may trigger an alarm. The system continues to evaluate the event as the real-time data is updated and this evaluation provides the drilling team with a continuously evolving probability that the event is occurring. This system helps the team make timely, informed decisions. The system requires minimal hands-on interaction to set up and uses data input via WITS for flow-in and flow-out measurements from typical rig sensors. The detection of drilling problems in real time using the QED software on several Integrated Project Management well construction projects is presented, including the lessons learned from deploying the technology in field operations. The significance of this development is to mitigate drilling risks during well construction projects, where minimizing NPT due to unplanned events is critical to success. Introduction The main problems during drilling are related to events such as kicks, stuck pipe, wellbore collapse, lost circulation, and equipment failures (Nilsen, 2002). Analysis of the majority of drilling problems has shown that there were early indications, which if correctly interpreted, could have helped to avoid the problem. However, it is well documented that post analysis is of limited use to real-time drilling operations. In order to realize the true value it is necessary to perform analysis in real time to provide key information as early as possible to the drilling team while it is still possible to take corrective action to reduce the cost and severity of events (Havrevold, Hwien, Parigot, 1991). There are a number of technology advances such as the increasing availability of real-time drilling data, from both surface and downhole sensors, open standards for real-time data access (Cayeux et al, 2006), new techniques in signal processing, and the computing power to process the data in real time. In 2006, events within an Integrated Project Management company involving well control cost USD 3.3 million, and lost circulation USD 2.6 million. Application of the QED software on integrated well construction projects is now demonstrating the potential to significantly reduce these through early detection and improved risk mitigation. QED was initially developed by Schlumberger Cambridge Research as a proof of concept of Bayesian methods to real-time data analysis and event detection. The identification of kicks from the analysis of delta mud flow and tank volume changes was selected as the first application of this technique. This process has been described previously (Hargeaves, Jardine, Jeffryes, 2001). Field testing during drilling in the Burgos field in Northern Mexico in 2002 revealed several practical issues, including inconsistent data processing, which resulted in excessive false alarms and difficulties in managing the complex code required to calculate probabilities and normalize and sum the results. As a result, field personnel did not accept the technology.
- North America > United States (1.00)
- North America > Mexico > Tamaulipas (0.34)
- North America > Mexico > Nuevo Leรณn (0.34)
- (2 more...)
- North America > Mexico > Tamaulipas > Burgos Basin > Burgos Field (0.99)
- North America > Mexico > Nuevo Leon > Burgos Basin > Burgos Field (0.99)
- North America > Mexico > Coahuila > Burgos Basin > Burgos Field (0.99)
- Information Technology > Sensing and Signal Processing (1.00)
- Information Technology > Architecture > Real Time Systems (1.00)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Uncertainty > Bayesian Inference (0.88)
- Information Technology > Artificial Intelligence > Machine Learning > Learning Graphical Models > Directed Networks > Bayesian Learning (0.88)
Abstract The marine environment offshore California is an environmentally sensitive location. To minimise environmental impact, platforms installed in the 1980's continue to be utilised for field development without the requirement to install additional jackets or disturb the seabed with subsea completions and flow lines. As the field developments continued, extended reach drilling (ERD) techniques were developed and employed to exploit the outer reaches of the fields and develop new satellite deposits. In order to fully utilise the capabilities of the existing platforms and as they became slot constrained, ERD sidetracks from existing ERD wells became necessary. Some of these sidetracks required highly complex three-dimensional profiles to reach the new targets. This paper discusses some of the challenges drilling offshore California and how the use of extended reach drilling techniques allowed full utilisation of available drilling infrastructure while minimising environmental impact. Also discussed is the specialist drilling technologies employed on these challenging wells together with lessons learned, illustrated with examples from real wells. California - A History of Innovation California has a long history of innovation in the drilling industry. In the 1890's many drilling rigs were erected along the shore-line. It soon became apparent that the oil reservoirs extended out under the ocean and, in 1897, a pier was erected to place a rig "offshore". This is reported as being one of the very first wells to be drilled from over water (similar activites are said to have occurred in a similar timeframe in the Caspian Sea from Baku, Azerbaijan and Lake Erie, from Pennsylvania, USA). In 1932 an offshore platform was built. This was possibly the first ever offshore drilling platform to be built anywhere in the world. In 1954, a man-made drilling island was built 1.5 miles offshore from Seal Beach. Again, this is reported by some as the first ever man-made offshore drilling island in the world. Another technical innovation pioneered in California was controlled directional drilling. In 1929, Mr H. John Eastman developed techniques to allow drilling of wells from rigs located on-shore to reach oil deposits beneath the ocean. Mr Eastman formed the worlds first directional drilling company, the Eastman Oilwell Survey Company. Since those pioneering days, technical innovations have continuously been developed and introduced to the drilling industry. Among these are the various techniques and technologies which allow wells to be drilled to ever increasing reach. This "Extended Reach Drilling" (ERD) is used increasingly to minimize the environmental impact in numerous locations around the world. This includes utilizing existing offshore facilities to drill to reserves distant from them. Drilling Legistation Offshore California Offshore drilling activity continued to expand in California until 1969 when a well control incident resulted in an oil spill in the Santa Barbara Channel. This incident resulting in stringent legislation related to offshore drilling activity. It was not until the late 1970's that any new offshore platforms were installed, and no new platforms have been installed since 1989.
- North America > United States > California > Santa Barbara Channel (0.24)
- Asia > Azerbaijan > Baki > Baku (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.47)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.34)
- North America > United States > Wyoming > Rocky Point Field (0.99)
- North America > United States > California > Santa Maria Basin > Point Arguello Field (0.99)
- North America > United States > California > Monterey Formation (0.99)
- Asia > Russia > Far Eastern Federal District > Sakhalin Island > Sea of Okhotsk > East Sakhalin - Central Sea of Okhotsk Basin > North Sakhalin Basin > Chayvo License Block > Chayvo License Block > Chayvo Field > Zone XVII/XVIII Formation (0.99)
Abstract Bitumen formations have posed significant challenges to deepwater Gulf of Mexico drilling operations. Many operators such as ConocoPhilips (Spa Prospect), Chevron (Big Foot), BP (Mad Dog) have reported bitumen encounters and associated significant costs. The current consensus is to avoid bitumen formations as much as possible. However, fundamental questions still remain unclear and controversial. For example, what bitumen behaves at in-situ conditions (i.e. high stress and high temperature), what shape is bitumen formation, what mechanisms drive bitumen into wellbore. This paper highlights a part of comprehensive efforts to drill through the bitumen encountered in a deepwater Gulf of Mexico field. A series of lab tests have been done to investigate the effect of temperature, pressure, and drilling fluids on bitumen mechanical behaviors. A material model for in-situ bitumen is therefore derived and applied in detailed 3D numerical analyses. At reservoir scale, the numerical models analyze the stress and deformation inside and around the bitumen formations with different lateral extensions and thickness, and evaluate the stability of various bitumen shapes at in-situ conditions. At wellbore scale, 3D models are used to study the factors of bitumen mobilization, including overburden stress, bitumen stress, and borehole pressure. The relative importance of each factor has been quantified. One of the key findings is the role of overburden in bitumen mobilization. We find that, for the bitumen encountered adjacent to the salt body, the radial stress gradient (i.e. horizontal if well is vertical) is dominant to flow the bitumen at the beginning after borehole introduction. The overburden effect becomes evident later. Further, both mechanisms result in stress concentrations within short distance around the wellbore. Another finding contradictory to previous publications is the mud pressure required to stop bitumen movement. The simulations indicate for the bitumen studied in this paper as long as the mud pressure at the bitumen formation reaches the level of in-situ minimum horizontal stress (i.e. fracture gradient instead of overburden gradient), the bitumen stops moving. However, even 0.25ppg mud pressure fluctuation may trigger the mobilization again. These studies improve the understandings of in-situ bitumen and near-wellbore bitumen flow conditions, and may help to develop a successful strategy to drill through. Bitumen, Tar, and Asphalt Before discussion, it is necessary to clarify and differentiate the following three carbon composites: tar, bitumen and asphalt. Based on Webster's Dictionary (1995), bitumen is "any of various mixtures of hydrocarbons โฆ often together with their nonmetallic derivatives that occur naturally or are obtained as residues after heat-refining natural substances โฆ", while tar is "a dark brown or black bituminous usually odorous viscous liquid obtained by destructive distillation of organic material". Krishnan and Rajagopal (2003) define asphalt as "a limestone that contains bituminous matter in a sufficient proportion, usually 7-12%, to become plastic when heated, and to cement the powdered limestone firmly when it sets on cooling." Interestingly but clearly, we should assign the term "bitumen" instead of "tar" to the material encountered in deepwater GOM as it is not a residue after refining. While most previous publications have referred bitumens to tars, we will use exclusively the term "bitumen" in this paper. Introduction The challenges associated with drilling into bitumen formations are not new to the operators in deepwater Gulf of Mexico (GOM). Many field developments, such as ConocoPhilips' Spa Prosepct at Walker Ridge (Rohleder et al., 2003), BP's Mad Dog field at Green Canyon (Romo et al., 2007), and Chevron's Bit Foot at Walker Ridge (Weatherl, 2007), have been affected. The problems encountered include spike in torque, increase of mud pressure, adhesion to BHA, closure of hole, etc.
- North America > United States > Gulf of Mexico > Central GOM (0.74)
- North America > United States > Texas (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.44)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 826 > Mad Dog Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 825 > Mad Dog Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 782 > Mad Dog Field (0.99)
- North America > Canada > British Columbia > Peace River Field (0.99)
Abstract An independent operator in offshore California has successfully achieved triple-zone intelligent well completions in an extended-reach drilling (ERD) campaign in its Rocky Point field. To date, two workover interventions have been performed in a total of five deployments in the field, of which three are currently fully operational. The Rocky Point reservoir is a highly fractured carbonate and can rapidly initiate water production. Achieving zonal isolation in the wellbore and at the reservoir level is critical. During the production stage it was recognized that two of the wells did not achieve the required zonal isolation evident by increasing water cut. Thus, the operator made the decision to retrieve these completions to conduct liner cement repairs. These triple-zone completions are controlled by 3ยฝ-in. tubing-retrievable flow-control valves, open/close and multiple-position, that work with dedicated gauges for monitoring of pressure and temperature. Each of the productive zones was isolated by three multiple-port retrievable production packers. The main challenges in retrieving these completions were:Conveyance of the cutting tools to depth (due to ERD profile); Accurate location of the cutting targets (+/- 6 inches at 18,000 ft MD); Severing all control/electric lines and pulling all 3 packers in the same trip; Redressing and re-running the completions within 2 weeks of retrieval. This paper describes the feasibility of deploying explosive jet cutters by pumping wireline conveyed assemblies to locator profiles above each packer, which allowed for simple, cost effective intervention, avoiding costly mobiliziation of tractors or coiled tubing. Lessons learned are shown on how completions components were affected by the cutting operation and the extent of their refurbishment before re-completion. The paper also identifies some modifications to intelligent completion design parameters (eg minimum distance of control valves from packers) that will be implemented in future installations. Introduction Even though the intelligent completion industry is maturing, (500+ installations), there is limited experience with the managed retrieval of these complex systems. This paper highlights the methodology, procedures and lessons learned associated with the retrieval of intelligent completions installed in ERD wells. ERD wells complicate retrieval due to the fact that the applied forces downhole are drastically reduced and thus reduces the potential to successful retrieval of pull-to-release devices. The Rocky Point Field is located 6 miles north west of Point Conception, offshore California (Figure 1).
- North America > United States > California (0.80)
- North America > United States > Wyoming > Campbell County (0.45)
- North America > United States > Wyoming > Rocky Point Field (0.99)
- North America > United States > California > Santa Maria Basin > Point Arguello Field (0.98)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Well Integrity > Zonal isolation (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract A new method of completing multiple-layer formations has been successfully tested in the United States and Canada. This new method places sliding sleeve valves in the casing string and completes the well with normal cementing operations. The sliding sleeve valves are opened one at a time to fracture layers independently without perforating. Completions using these casing valves are called Treat And Produce (TAP) Completions and have a unique design feature in the valves that allows a theoretically unlimited number of valves to be placed in a single well without incremental reductions to the internal diameter (ID). This near full bore feature allows normal cementing operations to be preformed with a special cement wiper plug. A control line is connected between sequential valves. When the bottom valve opens, the control line becomes pressurized and transfers the bore pressure to a piston in the valve immediately above. This piston squeezes a Cring and makes the ID smaller. At the end of the fracture treatment to the lower valve, a dart is dropped during the flushing operation. This dart lands on the squeezed C-ring and seals the bore inside the sliding sleeve. Pressure is then increased until the next valve is pumped open. When this valve opens, the next control line is pressurized, squeezing the next C-ring. The main feasibility issue with this cemented sliding sleeve concept was fracture initiation pressure through the cement and into the formation without perforated holes. Significant laboratory testing was conducted which predicted fracture initiation pressure to be similar to that encountered in openhole or even lower. Fracture initiation pressures were closely monitored during several field installations and confirmed that perforations were not needed to initiate fractures in the formations. This paper describes TAP Completions, how the TAP valves work, and how the valves performed. Information on a TAP Completion with 6 layers is presented in detail and an overview of all installations to date. Introduction The US and Canada tight gas market is deploying new methods to efficiently stimulate multiple-layer reservoirs, but the most common method remains the same. Most wells are completed with cemented casing. To stimulate the reservoir, a plug is set, one or more layers are perforated and then the layer(s) are stimulated as a stage. This practice is repeated multiples times until all the layers are stimulated. Most wells are flowed within 24 hours to remove the treating fluids from the reservoir. Operators seek to balance the quality and the cost of the stimulations vs. potential well production. One of the most important parameters affecting production is the number of layers fractured during a single stage. Stimulating multiple layers in a single stage is not ideal since layers with lower fracture gradients or formation pressure may take more of the treatment than planned, leaving the higher pressure layers only partially treated. This is becoming more of an issue as development wells are being drilled in more dense spacing, increasing the chances of treating some depleted layers. The Treat And Produce (TAP) Completion system has been developed to allow the efficient treatment of individual layers in cemented casehole completions. TAP Completions use special casing valves that isolate individual layers one at a time without any interventions. The TAP valves are near full bore and do not require incremental reductions of ID and thus allow normal cementing operations. The TAP valves also have unique helical ports that align to any preferential fracture plane, regardless of the orientation of the valve in the casing string. These ports ensure a single bi-wing fracture plane is initiated from the well bore and the fracture initiation pressure is kept to a minimum.
- North America > Canada (0.54)
- North America > United States (0.48)
- North America > United States (0.89)
- North America > Canada (0.89)
1.0 Incident Description 1.1 Sequence of Events This Case Study examines an explosion at the Partridge-Raleigh oilfield in Raleigh, Mississippi. The incident occurred at about 8:30 a.m. on June 5, 2006, when Stringer's Oilfield Services contract workers were installing pipe from two production tanks to a third (figure 1). Welding sparks ignited flammable vapor escaping from an openended pipe about four feet from the contractors' welding activity on tank 4. The explosion killed three workers who were standing on top of tanks 3 and 4. A fourth worker was seriously injured. In the weeks preceding the incident, Stringer's workers had relocated tanks 3 and 4 from other oilfield sites on the Partridge-Raleigh property to the #9 well site. On the day of the incident, the four workers were completing the piping connection between the tanks. To connect the piping from tank 3 to tank 4, the workers had to weld a pipe fitting onto the side of, and a few inches below the top of, tank 4. To prepare for the welding operation, they removed the access hatch at the base of tank 4 and entered the tank to remove the crude oil residue. Then they flushed the tank with fresh water and allowed hydrocarbon vapor to evaporate for several days. They did not clean out or purge tanks 2 and 3. On the day of the incident, the welder inserted a lit oxy-acetylene welding torch into the hatch and then into the open nozzle on the opposite side of tank 4 to verify that all flammable vapor was removed from the tank before welding began. The welder was not aware that this act, called "flashing" the tank, was an unsafe practice. Next, the foreman (F) climbed to the top of tank 4 (figure 2). Two other maintenance workers, (M) climbed on top of tank 3; they then laid a ladder on the tank roof, extending it across the 4 foot space between tank 3 and 4, and held the ladder steady for the welder (W). The welder attached his safety harness to the top of tank 4 and positioned himself on the ladder. Almost immediately after the welder started welding, flammable hydrocarbon vapor venting from the open-ended pipe that was attached to tank 3 ignited. The fire, which immediately flashed back into tank 3, spread through the overflow connecting pipe from tank 3 to tank 2, causing tank 2 to explode. The lids of both tanks were blown off. The three workers standing atop the tanks were thrown by the force of the explosion and fell to the ground. The welder was also thrown off the ladder, but he was wearing a safety harness that prevented him from falling to the ground. Volunteers from the local fire department and personnel from the county sheriff's office quickly responded to the incident site following an eyewitness' 9โ1-1 emergency call. Emergency Medical Technicians provided first-aid to the victims. Two victimsโthe foreman and one of the maintenance workersโdied from their injuries at the scene, and the third maintenance worker died while in transport to the hospital. The welder survived, but suffered a broken ankle and hip.
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Mississippi > Stringer Field (0.99)
- North America > United States > Mississippi > Raleigh Field (0.99)
Abstract The JV operator was looking for a combination of technologies to optimize drilling in Canada's Mackenzie Delta region. The area is characterized by a permafrost section up to 2,000 ft (609 m) thick. This shallow permafrost section is dominated by unconsolidated silt with freshwater ice ranging from 60% volume to pure ice layers. Historically, mechanical heat input has melted the frozen layer, resulting in increased hydrates/shallow gas risks, extreme hole enlargement/cleaning problems, rig support issues, wellbore instability, stuck pipe, hydraulic isolation, and environmental impact issues. Optimizing drilling operations through the shallow section is critical to maximize the number of wells that can be drilled with the available rigs in this limited-access area. To move the rig requires approximately 3 ft (1 m) of ice cover, which significantly limits the operating season, increasing the need for rig efficiency and reduction of non-productive time (NPT). The industry has endorsed the importance of mud cooling through the shallow permafrost and the underlying hydrate-bearing formations to avoid borehole instability and to control hydrate dissolution. However, the industry has struggled to maintain sufficiently cold mud at the high pump/power rates required to effectively drill/clean the larger surface holes. To solve the challenges, the operator utilized a casing-while-drilling (CwD) and casing bit system with a unique-to-the-industry mud-chilling technology and a variety of controlled drilling parameters. The CwD and casing bit system allowed the operator to drill and set casing through the problematic zones in one operation with relatively low flow rates to avoid hole enlargement. The lower flow rates also enabled the use of smaller, lighter rig equipment that reduced the required ice thickness to move the rig and therefore increase the winter season operating period. Following the successful implementation of the CwD and casing bit system on the first well of a winter program, the second well was drilled safer with the elimination of a casing string, which further reduced drilling time and cost. Introduction Oil and gas operators have explored in the Arctic regions of northern Canada, Alaska, and Russia for more than 40 years. Early drilling campaigns encountered significant problems drilling through the shallow permafrost sections due to degradation of drilling conditions as a result of permafrost thaw. Experience from these earlier operations and experiments conducted by Kutasov et al (1988) has highlighted the need to maintain chilled drilling mud to minimize permafrost thaw during the well construction process. Production operations in the Canadian Arctic have not yet reached development stage. Industry experience in other Arctic regions, including Alaskaโas well as Canadian National Energy Board (NEB) regulationsโdictate a need to protect permafrost substrata through the entire life cycle of the well.
- North America > Canada (1.00)
- North America > United States > Alaska (0.68)
- Asia > Azerbaijan > Aran Region > Middle Caspian Basin > Yevlakh-Aghjabady Depression > Muradkhanli-Jafarli-Zardab Block > Muradkhanly Field > M-45 Well (0.94)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > Block WA-209-P > Reindeer Field (0.89)
- North America > Canada > Northwest Territories > Beaufort-Mackenzie Basin > Taglu Field (0.89)
Abstract There is significant discussion concerning what type of Rotary Steerable System (RSS) provides the best-quality hole, and which key characteristics of the drill bit, along with a particular RSS, will produce the optimal balance between stability and steerability in directional wells. Although some evidence can be drawn from field performance with various tools and customized drill bits, these results can often be inconclusive due to the large variance in factors involved with commercial drilling. This paper describes an extensive series of test wells drilled in a controlled and non-commercial environment, allowing single step changes in both the drill bit features and Rotary Steerable (RS) configurations. The testing is unique in that the specific RSS works in shop-configurable point-the-bit and push-the-bit modes. Between two distinct RSS operation modes, consistency in stiffness, weight, force applying capability, and control systems lead to a direct comparison of bit performance. A unique sensor system, integrated into the specific RSS, provided real-time measurement of near-bit borehole caliper and near-bit stick-slip and vibration. This feature allowed real-time evaluation of bit and BHA stability and borehole quality. After each test run, memory data was retrieved and used for more detailed assessment of bit performance. Drill bit tests were systematically structured in a controlled environment so that the relationship between gauge geometry and configuration could be examined without alteration of the cutting structure. As a result, comparison between stability, dogleg capability, torque and drag, and borehole quality was solely dependent upon gauge length and geometry. Further, the systematic testing led to the conclusion that a specific gauge design related to effective side cutting and gauge stabilization is crucial for optimized RS drilling in both point-the-bit and push-the-bit configurations. Introduction In the 90's, the introduction of the first commercial RSS revolutionized directional drilling 1. Since then, RSS technology has made remarkable improvements in reliability and has become a standard drilling tool. Today, point-the-bit and push-the-bit RSS are utilized on both directional and vertical wells worldwide. Their use is not only limited to high-cost offshore markets but is now becoming more common in lower cost land markets. The advancement of RS drilling technology goes hand in hand with the use of polycrystalline diamond compact (PDC) bits. Continual development of advanced modeling software and cutters with significantly increased abrasion resistance have led to PDC designs that can drill faster, further and with a high degree of stability. These benefits, combined with the appropriate RSS, can also deliver superior directional control, improved borehole quality, higher-quality logging and easier casing runs. This resultant improvement in economics is particularly attractive in high-cost offshore wells.
- North America > United States > Oklahoma (0.68)
- North America > United States > Wyoming (0.46)
- North America > United States > Texas (0.46)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Teapot Dome Field > Wall Creek Formation (0.99)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Teapot Dome Field > Tensleep Formation (0.99)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Teapot Dome Field > Sussex Formation (0.99)
- (6 more...)
Abstract This paper presents the results of a two-year comprehensive effort to design, test, and qualify third-generation rotary-shouldered connections (RSC) for 20,000 psi internal and 10,000 psi external pressure service. ISO13679 testing methodologies for casing and tubing were modified to evaluate the RSC pressure capability. Results from comprehensive finite element modeling and extensive laboratory testing designed to reproduce the harsh, aggressive loading modes and high pressures encountered in field use are presented. The result of this program is a RSC that incorporates a double-start thread form to reduce the number of revolutions to assemble the connection by 50 percent reducing trip time. The thread form also provides a unique dual-radius thread root that offers a step change improvement in fatigue resistance. A metal-to-metal seal provides pressure integrity. In addition to providing a 20,000 psi internal and 10,000 psi external pressure rating, the new connections provide increased mechanical and hydraulic performance compared to second generation high torque connections while also providing fatigue performance greater than standard API connections. Introduction New developments in drilling tubulars are rapidly evolving and represent enabling technologies for the industry's continued advancement of drilling deeper, further and more cost-effective wells. Much focus has been made toward the advancement of RSC technology to permit high torque drilling of extended reach, directional and horizontal wells. In response to this need, the development of third generation, ultra-high torque connections was recently announced providing reduced tripping times and the mechanical and hydraulic load requirements for drilling today's deepwater, extended reach and ultra-deep wells. The next step in the evolution of RSCs has now occurred with the development of a third-generation, gas-tight, pressure rated connection providing enabling technology for high-pressure completion and workover, drill-stem testing, UBD and intervention riser applications. Although drill pipe, drill pipe connections and drill stem materials represent mature technologies, innovations are being developed in these areas. This third generation gas-tight, double-shoulder connection presented here represents several advancements that address some of the challenges ahead. Double-Shoulder Connection Design Development First generation double-shoulder connections (1st Gen. DSC), see Figure 1, were introduced in the early 1980's.4 1st Gen. DSC's were basically API rotary-shoulder connections (primarily NC or FH) with a second torque shoulder added inside the box member at the pin nose interface.1,3 These 1st Gen. DSC's incorporated the same basic design features in terms of thread form, taper, lead, pitch diameters, etc. as the API connection on which they were based. These connections yielded a simple, straight forward solution that increased the connection torsional strength by approximately 40 percent over the corresponding API connection.
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 640 > Tonga Field > Tahiti Well (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 640 > Tahiti Field > Tahiti Well (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 640 > Caesar Field > Tahiti Well (0.99)
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- Well Drilling > Drillstring Design > Drill pipe selection (1.00)
- Well Drilling > Drilling Equipment (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
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