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ABSTRACT The Lost Hills oil and water gathering system was not designed to handle microbiologically influenced corrosion (MIC). A number of system changes combined to cause prolific bacterial growth in a system in which bacteria had been relatively inactive. MIC has been mitigated using a combination of an effective biocide treating program, installation of an extensive pipeline pigging system, the use of MIC resistant materials, a vessel cleaning program, and an extensive monitoring program. The history of MIC at Lost Hills along with the cost and extent of MIC to this production system are presented. MIC, sulfate reducing bacteria (SRB), acid producing bacteria (APB), corrosion, pitting, biocide treating, gathering system, production equipment, filters, pigging, water quality, sessile, and planktonic. INTRODUCTION The Lost Hills Field is located in the San Joaquin Valley, approximately 50 miles (80 km) northwest of Bakersfield just off Interstate Highway 5. The approximate location is shown in Figure 1. The field itself is approximately 2 miles wide and 5 miles long (3.2 km by 8 km) as shown in Figure 2. The Lost Hills Field is somewhat unique in that the oil is deposited in a diatomite formation which has very high porosity, but virtually no natural permeability. Because the low permeability limited primary oil recovery, the field was not heavily developed until the late 1980?s when a field wide program was initiated to hydraulically fracture the reservoir. ,The field is also unique in that the produced water contains 15 ppm of soluble iron which reacts readily with hydrogen sulfide and oxygen to form solids. Hydraulic fracturing is a process in which guar polymer (a complex sugar) mixed in water is crosslinked to form a viscous gel that enables coarse sand to be pumped into the wellbore at pressures which fracture the oil producing formation. When the pressure is released, the sand remains in the fractures, creating a permeable path for oil to follow to the wellbore, thereby increasing production.. The guar polymer is produced back with production fluids into the surface facilities in the water phase. Based on this technology, an intensive well drilling program was instituted in Lost Hills in 1989 to recover the relatively light crude. To accommodate the new development program, a new production gathering system and central oil and water cleaning plant were built in 1990. The gathering system consists of groups of 30 to 60 wells feeding into 24 gas/liquid separation sites located throughout the field as shown in Figure 3 and 4. At these locations the production from individual wells can be measured in 3-phase separators while production from the rest of the wells enters a large 2-phase separator. From this separator, oil and water enter the gathering system as shown schematically in Figure 4, and flow to the oil and water cleaning plant. A separate pipeline system transports the gas to a compression plant. The pipelines and gas/liquid separation equipment were constructed from uncoated carbon steel since mild carbon dioxide corrosion was anticipated and could be controlled with chemical inhibitors for the 15 year design life of the system. The new gathering system was also intended to minimize the pressure drop from the well to the plant while handling 80,000 to 100,000 barrels of gross fluids (12,720-15,909 m3). For this reason, the gathering system is composed of 8 (20.3 cm), 12 (30.5 cm) and 16-inch (40.6 cm) diameter pipelines. The oil and water cleaning plant consists of two 5000 bbl (795 m3) wash tanks, two 8,000 bbl (1272 m3) shipping/reject tanks and induced gas flotation equipment for final water cleaning, as shown in Figure 5, Plant construction materials consisted
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design (1.00)
- (2 more...)
ABSTRACT The Department of Transportation and its Office of Pipeline Safety have been involved with in-line inspection (ILI) pigs since the construction of the Alaska crude oil pipeline in the early 1970s. Two Congressionally mandated reports concerning ILI pigs and a regulation requiring new and replaced pipe and components to be designed and constructed to accommodate ILI pigs have been issued by the Department. Although there is no present federal requirement to run ILI pigs, they are required by the Office of Pipeline Safety in selected compliance cases. The Department will continue to use ILI pigs in compliance cases. It also supports future ILI pig research, and the use of ILI pig surveys incorporated in any pipeline operator?s future risk management plans developed as safety alternatives to the established pipeline safety regulations. The Department also in the future may require ILI pigs to be run on some pipelines. INTRODUCTION An in-line inspection (ILI) device is a pig which passes through a pipeline propelled by the commodity being transported that can detect certain irregularities or anomalies in the pipe wall. This type of pig records the existence, location, and relative severity of the anomalies through use of recording equipment carried on board the pig. ILI by pigs, also known as smart pigs, has been around since the 1960s. Regulations were issued in 1969 for hazardous liquid pipelines (49 CFR Part 195) and in 1970 for gas pipelines (49 CFR Part 192). Both sets of pipeline safety regulations contain requirements for pipeline inspection. Neither requires the use of ILI pigs. This paper will trace the history of DOT?s involvement with ILI pig, The paper also will discuss the present activity within DOT concerning ILI pigs and will provide some insight into future DOT activities in the area of ILI pigging. HISTORY Of DOT INVOLVEMENT WITH ILI PIGS Crude Oil Pipeline in Alaska The First DOT involvement with ILI pigs was in the early 1970s in connection with construction of the Trans-Alaska crude oil pipeline system. A technical stipulation in the right-of-way agreement between the pipeline?s perimeters and the Department of the Interior, the federal agency with primary oversight of construction of the pipeline, required the development of a pipe deformation monitoring system. The stipulation was included in the agreement because of the government?s concern about possible settlement of the buried, hot pipeline in areas containing unidentified thaw unstable ice-rich permafrost. The Superpig curvature pig was developed in response to the stipulation in the right-of-way agreement. The curvature pig was a three section articulated ILI pig 14-feet long weighing 5,000 pounds. The center, or transducer, section contained sixteen wheels that contacted the pipe through connections with spring-loaded arms. Differences in the distance traveled by the wheels determined the curvature of the pipe. It was run a number of times in the pipeline, but discontinued when it became lodged in a valve cavity and had to be removed in pieces through the valve bonnet. DOT?S Office of Pipeline Safety (OPS) also participated in the drafting of the corrosion control plan for the Pipeline. OPS is the office within DOT?s Research and Special Programs Administration (RSPA) responsible for administering the DOT?s pipeline safety program. As a result of the OPS recommendation to the Department of the Interior. a schedule for conducting magnetic flux leakage pig surveys was included in the plan. Initial Congressional Interest in ILI Pigs The first time ILI pigs were discussed publicly in Congress was in March 1984 testimony before the House of Represe
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
- Facilities Design, Construction and Operation > Facilities Operations > Pipeline pigging (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (0.93)
ABSTRACT Pigging, Gelatin, Gel Pigging, Crosslink, Cleaning, Production Pipelines, Pipelines, North Slope, Kuparuk, Prudhoe Bay, Alaska ABSTRACT Many oil fields, such as that at Kuparuk, on the North Slope of Alaska, have been built as a trunk and lateral gathering system, with many different pipeline diameters in a branched network. No launchers nor receivers were built for the Kuparuk oil production pipelines. The high cost of retrofitting launchers and receivers prompted investigation of alternative methods for cleaning the pipelines. This paper describes a novel approach to mold solid gelatin pigs in bypass lines, and to run those pigs through the production pipelines to the primary separators. The gelatin pigs would slowly melt, eliminating the need for receivers. Field and laboratory testing showed that gelatin pigs could not effectively clean the pipelines. The addition of cross linking agents could increase the mechanical integrity of the gelatin pigs, but also elevated the melting temperatures above the operating temperatures of the primary separators. As such, they were not meltable (in time), and nc~ benefits could be obtained by the use of solid gelatin pigs for cleaning applications. INTRODUCTION The Kuparuk oil field is located on the North Slope of Alaska, approximately 40 miles [65 km] west of Prudhoe Bay. Approximately 300,000 barrels of oil are produced daily [47,690 kLOPD] from the A and C Sands of this reservoir. The production comes from 431 producing wells at 42 drill sites throughout the field. The oil gathering system at Kuparuk has been designed as a trunk and lateral system, wherein production from different drill sites are merged together into successively larger pipelines, and then flow into the Central Processing Facilities (CPF) for separation of the oil, water, and gas. The diameter of the trunk lines typically vary from 12 inches [30.5 cm] to 14 inches [36 cm] to 16 inches [41 cm] to 24 inches [61 cm], as each line approaches the CPFS. All pipelines are above ground, and are insulated. Each of the production pipelines accumulate formation sands, frac proppant, and corrosion products during normal operations. The quantities vary, based on the physical and chemical environment within each lines. These deposits may obscure radiographic inspection results, and could hinder the ability of corrosion inhibitors to protect the pipewalls from underdeposit corrosion. Thus it is desireable to keep the pipelines as free as practical from such depositions. The Kuparuk production pipelines were not designed and built to include pig launchers or receivers. Further, the retrofit installation of such equipment would have been extremely expensive, since separate pig launchers and receivers would be needed for each segment (line diameter) of each production pipeline. Therefore, other approaches were sought to enable cleaning of the interiors of the pipelines. This paper discusses the concept of solid gelatin pigs to accomplish this task. At the same time that Kuparuk was investigating new approaches to enable cleaning of the interior of the pipelines, Prudhoe Bay was considering new ways to apply corrosion inhibitors to their pipelines more efficiently. One method under consideration was the use of solid gelatin pigs, which would rub (ablate) against the 140ยฐ F [60ยฐ C] pipewall at Prudhoe Bay. Although Kuparuk and Prudhoe Bay were both evaluating the use of solid gelatin pigs, the objectives were distinctly different. This will be discussed in more detail. However, first, there needs to be an overview of Prudhoe Bay, as related to production pipeline pigging. (Many of the questions related to Kuparuk?s objectives were addressed by cooperative efforts and specific field t
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > Kuparuk Field (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.89)
ABSTRACT To gain a financial benefit, a smart operator views inspection as part of an overall strategy to maintain a safe pipeline. This paper shows how periodic internal inspections, followed by defect assessments using fitness-for-purpose criteria and selective repair, is the most cost beneficial way of maintaining the safety of a pipeline. [t is highlighted that it is important to use (i) genuine high resolution pigs for the inspection and (ii) expert fitness-for-purpose assessment. The cost savings on the optimized future safe operating strategies for the pipeline offset the costs of the inspection and expert assessment. INTRODUCTION Pipelines are recognized as the safest method of delivering energy [ I ]. However, pipelines, like all engineering plant can, and do, fail. A number of transmission pipelines have failed recently, with both tragic and spectacular effect [2-6]. For example in Venezuela in 1993, 5 I people were burnt to death when a gas pipeline failed and the escaping gas ignited. More recently ( 1994), a pipeline failed in New Jersey, USA, and the resulting fireball killed one person and injured 58 others. There have been other recent reports of pipeline failures in Russia, Pakistan, Argentina, Canada and Britain. Pipeline failures rarely cause fatalities to the public [1], but they can disrupt an operator?s business, either by loss of supply, or by necessary remedial work. They can be extremely costly in terms of replacement and repair. For example, the BP Forties oil pipeline in the UK North SEA has had to be replaced due to internal corrosion at a cost of $250 million, and a single pipeline failure can cost tens of millions of dollars if it occurs in an environmentally sensitive area [7]. An operator needs to maintain a safe pipeline, and ensure it has a long and profitable life. Consequently, be must consider maintenance measures that are both cost effective and prevent failures or large repair bills. Internal inspection of a transmission pipeline using intelligent pigs is increasingly being used by pipeline operators as a means of both maintaining their pipelines and ensuring that their major asset has a long and efficient life, We have internally inspected most of our 18,000 km high pressure pipeline system, and are now able to reduce maintenance budgets. The company can now look to the future with confidence in the knowledge that it knows the condition of its (mainly 25 year old system) pipelines, and can demonstrate to Regulatory Authorities their safety, potential for uprating and potential for an infinite design life. This paper is aimed at answering the type of questions a pipeline operator should ask in formulating a strategy to ensure that internal inspection is a smart investment. The paper starts by covering maintenance and inspection methods in general. WHY MAINTAIN AND INSPECT A PIPELINE? Engineering plants follow a ?bath tub? failure probability curve, Figure 1. This curve shows that during a structure?s design life the highest failure probability is when the structure is new, or when it is old. This curve applies to automobiles, aircraft etc., and pipeline operators will identify with it; pipelines have high failure rates early in life (e.g. hydrotest) and later in life (due to corrosion). An inspection of a pipeline will help to extend the low probability portion of Figure I - the goal for the pipeline operator being to extend the design life of his pipeline to 80 or even a 100 years, Figure 1. HOW TO MAINTAIN A SAFE PIPELINE? What Methods are Available and What do they Prevent/Detect? Pipelines can be, and are, routinely inspected and monitored using many direct and indirect techniques. well documented [8,9] and aim to
- North America > United States (1.00)
- Europe > United Kingdom > North Sea (0.55)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Piping design and simulation (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Offshore pipelines (1.00)
- (2 more...)
ABSTRACT The paper presents the authors viewpoint on the current state of in-line inspection technology. The issue of considering the sizing accuracy of the in-line inspection tool in monitoring corrosion defect growth and making repair decisions will be covered by the paper. Why Smart Pig? Smart Pigging is a cost effective way of determining the true integrity of a pipeline system. It is a useable tool in protecting the environment and public safety. However, it has its limitations so it does not totally replace the use of other methods to monitor pipeline integrity. Nor should it be considered the only way to monitor pipeline integrity. Itiormation from a smart pig metal loss survey can be used for optimizing maintenance and can be used sometimes to avoid the need for hydrotesting. Current Government Regulations Currently, the use of smart pigs are not required by federal or state agencies. Federal regulations give minimum requirements for pipeline operation that assume that the pipeline operator will use state-of-the-art technology to maintain pipeline integrity. Failure of pipeline operators to cost effectively use new technology to maintain pipeline integrity may result in regulations that force the use of new technology in a way that is not cost effective. Alternatives to Smart Pigging Close interval pipe-to-soil surveys, hydrotesting. or periodic buried pipeline inspections are considered alternative methods to smart pigging. Like smart pigging, each inspection method has its advantages and limitations. Choosing a Smart Pig Inspection Tool Competition between smart pig inspection companies has resulted in improved inspection tool performance at lower cost. The gap between the advanced and conventional MFL (Magnetic Flux Leakage) inspection companies is narrowing. Although advanced MFL tools have advantages over conventional MFL tools, the additional cost of running a higher resolution MFL tool cannot always be justified. Both advanced and conventional MFL tools are subject to the universal limitations of MFL inspection such as minimum inspection speeds, maximum pipe wall thickness, and the difficulty of indirectly measuring the depth, length, and shape of a corrosion pit from a MFL signal. A MFL tool can never be 100% accurate because of the fact that it measures metal loss indirectly. Although Ultrasonic tools measure defect size directly, they have other limitations that limit their use.
- Energy > Oil & Gas > Midstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.48)
ABSTRACT In-line inspection tools?, smart pigs, are devices that detect magnetic irregularities or anomalies in the wall of the pipe that includes corrosion, gouges, and material defects that exhibit metal loss. However, they do not normally detect stress corrosion cracking (SCC), hydrogen embrittlement, hard spots, certain types of horizontal defects, and anomalies on or near the girth weld. Dents if significant, casings, and foreign metallic objects if touching the pipe may also be detected qualitatively. Also, features such as welds, valves, taps, flanges, test station plates, and other appurtenances can be identified. Case histories and field findings using the newly developed 30 (76.8 cm) x 24 (60.96 cm) and 36 (91 .44 cm) x 30 (76.8 cm) collapsible smart pigs will be discussed. In addition, the results of the first generation smart pigs with enhancements consisting of hardware developments, new field logs, and software will be presented. INTRODUCTION Transco started running smart pigs in 1967. In 1987, it became formal company policy to inspect the main line system of 24 (60.96 cm), and greater, diameter pipelines from Texas to New York. The pipeline system primarily consists of two (2) 30 (76.2 cm) diameter lines, one (1) 36 (91 .44 cm) diameter line and one (1) 42 ( 106.68 cm) diameter lines that run parallel along the Gulf Coast of Texas, Louisiana, Mississippi, and Alabama, and then to the East Coast via Georgia, the Carolinas, Virginia, Maryland, Pennsylvania, New Jersey, and into the city gates of New York City. Main line segments for inspection were selected on a matrix system that considered population density. diameter, age, reduced pressure areas and a history of corrosion, poor coating, low pipe-to-soil potentials, disbonded coating, shielding and stray currents. It should be noted that early smart pigs w-ere r-m with varying degrees of success. However, today?s improvement in techniques, instrumentation, and magnetics has increased the accuracy of the first generation type tool. To date, approximately 22of our main line system has been pigged with the acceptable accuracy of the tool capabilities. PIGGING PROGRAM The primary problem of not pigging more pipelines has been the cost of modifying the piping system to make it more readily piggable, either on a temporary or permanent basis. Most of the system consists of reduced port valves with inadequate launcher and receivers. During the design and construction phases of many systems in the 50?s and 60?s, line pipe diameter availability was increasing faster than valve size. Costs and perceived true need for machining valve diameters were also a big decision factor. It became apparent from the onset that high costs were associated in doing conventional type of smart pigging. It should be noted that plug valves cannot be pigged and must be cut out and replaced, however, sphere, ball, and gate valves i.e. oval without internal restrictions will allow a pig to traverse. Costs were running as high as $86,000/mile ($53,440/km) kilometer) for a 30 (76.8 cm) diameter non-piggable line as compared with $23,000/mile ($14,292/km) for a piggable line. It should be noted that leasing the pig was the lowest cost of the project.
- North America > United States > Texas (0.56)
- North America > United States > New York (0.45)
ABSTRACT Intelligent pigging of on-shore and off-shore pipelines in the U.K. has been carried out for a number of years. Case histories are discussed and some of the problems faced by pipeline operators in implementing a programme of intelligent pigging are examined. The Regulators? roles in this activity arise from powers conferred by the Pipe-1ines Act 1962 (applicable to on-shore pipelines), and the Petroleum and Submarine Pipe-lines Act 1975 (applicable to off-shore offshore pipelines). Much of this legislation will be replaced by new Pipeline Safety Regulations in 1996. This new legislation and the reasons for change are described in the paper. INTRODUCTION Regulatory Regime Prior to 199 I the Department of Energy was the U.K. statutory body responsible for all regulatory matters concerning pipelines, safety issues being handled by this department for the Health and Safety Executive (HSE)[ 1) under an internal agency agreement. In 1991, following the public inquiry into the Piper Alpha Disaster, responsibility for regulation of pipeline safety was transferred to the HSE. Responsibility for regulation of planning and resource development issues was transferred to the Department of Trade and Industry (DT1 ). Intelligent Pigging There has been no general, indiscriminate, statutory requirement for intelligent pigging of on-shore or off-shore pipelines in the U.K. in the past and there is unlikely to be such a requirement in the future. However, operators are encouraged to build pipelines in such a manner that it would be possible to inspect them by such means in the future. Intelligent pigging has, however, been required by the regulator on a case by case basis after consideration of the operating duty and the risks arising from operation of the pipeline. This requirement has been enforced by the appropriate regulator using the powers available under current legislation which are described in more detail below. There have been instances when programmed of intelligent pigging have been impossible to achieve due to unforeseen circumstances, despite the best endeavors of all concerned. These situations have been resolved on] y with a frank openness on the part of the pipeline operator and a pragmatic approach by the regulator, The case histories examined will include some of these situations.
INTRODUCTION ABSTRACT To ensure the integrity and serviceability of gas pipelines, operators periodically utilize intelligent pigging. This inspection technique has proven to be a cost effective approach for determining the condition of operating pipelines. Recent advancements in intelligent pigging technology are now aiding the pipeline industry in the detection of stress corrosion cracking. In the United States the average age of natural gas transmission pipeline systems is nowover25 years,(l)Some pipe was installed prior to 1945,andis still in service, Over the years this gas transmission system has become a national asset that provides vital energy to industry, buildings and homes through out the nation. Therearemorethan280,000 Miles of high pressure gas transmission pipelines in the United States. Tore place the system would be prohibitively Expensive consequently, the industry must relyon advanced means for maintaining their pipeline systems well as developing new means for ensuring the system?s integrity, reliability and safety. To ensure the integrity, reliability and serviceability of the gas transmission pipelines, pipeline operators use many different preventative maintenance methods and practices. The experience of pipeline industry coupled with the use of advanced technology are key elements in providing new and improved methods for monitoring, inspecting and surveying pipelines to ensure their safety. Right-of-way surveys, gas leakage detection patrols, measurement of cathodic protection currents, use of in-line inspection (ILI) intelligent or smart pigs, hydrostatic testing, hellhole excavations to gain direct access for inspection of buried pipe and geographical information computer modeling to predict suspect areas are some d) the methods being used by the gas industry. For many situations, the use of ILI tools has proven to be a cost effective approach for appraising the condition of such parameters as geometric distortion and metal loss due to corrosion. Currently there are no commercially available ILI tools for detecting axial crack-like anomalies or defects, such as stress corrosion cracking (SCC) and seam weld cracks, in gas transmission pipelines. There are, however, several research and development efforts being co-funded by the gas transmission pipeline industry toward developing such an ILI tool. Failures attributed to SCC represent a small percentage (e.g., <1 ,5Yo)of the total incidents reported to the U. S. Department of Transportation, Research and Special Programs Administration, Office of Pipeline Safety (OPS). However, because SCC is difficult to detect and can result in catastrophic failures, pipeline operators have placed increased emphasis on development of ILI techniques for early detection of this condition. At the present time, operators rely on knowledge of the pipeline conditions, nondestructive evaluation (TJDE) and/or hydrostatic testing to locate and characterize SCC in gas transmission pipe. When hellholes are dug and the coating removed, NDE methods such as magnetic particle, ultrasonic and visual inspection can be used to characterize detected flaws. In some instances, radiography is used to characterize anomalies in welds and imperfections in the pipe wall. Due to the various limitations of these methods, an ILI device capable of detecting SCC would be of a significant benefit to the natural gas pipeline industry.
- Energy > Oil & Gas > Midstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
- Facilities Design, Construction and Operation > Facilities Operations > Pipeline pigging (1.00)
ABSTRACT oil and gas production operations use intelligent pigs for corrosion inspection of gathering systems and pipelines worldwide, The authors have been involved with intelligent pig inspections which have been conducted on over 155 different pipelines owned by one international corporation. A variety of intelligent pig vendors have been used with tools ranging from standard first generation magnetic flux leakage (MFL) to high-resolution MFL to standard and custom made ultrasonic (UT) tools. Experiences encountered during these inspections are discussed and resolutions to many of the problems are described. INTRODUCTION Exxon production operations use intelligent pigs for corrosion inspection of gathering systems and pipelines worldwide. The authors have been involved with intelligent pig inspections conducted on over 155 different pipelines. A variety of intelligent pig vendors have been used with tools ranging from standard first generation magnetic flux leakage (MFL) to high-resolution MFL to standard and custom made ultrasonic (UT) tools. The vast majority of these inspections have run smoothly with little or no problem and have provided valuable data on the pipeline condition. It has been common practice to perform digs to confirm or calibrate the results of the inspection for onshore pipelines. Offshore this is not practical and confirmation is often not possible. Most of the pipelines surveyed have been subsea pipelines, The tools that have been run have only inspected for metal loss and no inspections for cracking or weight coat loss have been carried out. Such services are outside the scope of this review. This paper concentrates on the problems experienced, but this is not to imply that the technology is of little use. Overall our assessment of intelligent pig inspections is that, used and interpreted correctly, they provide invaluable information to the corrosion engineer. The information that is provided helps the engineer to assess the condition of a pipe and the effectiveness of the corrosion control program. However, it should be emphasized up front that intelligent pig inspections are being used as a tool for the corrosion engineer. The results of these inspections require a review that considers the inspection results and the service that each pipeline has seen. As the following situations will demonstrate, the results cannot always be taken strictly at face value and require the inclusion of some professional judgment, A successful intelligent pig inspection is not as simple as bidding the job, calling out the vendor and then reading the report, A variety of problems can be experienced that can invalidate either the data that the pig produces or the interpretation that is provided in the report. Successes and failures have been experienced with every major vendor; so even an approved vendor list does not guarantee a successful test or preclude problems. This also does not mean that the problems are always the fault of the vendor. Some problems occur that are due to inherent limitations of intelligent pigging technology, others are to problems with the pipeline being inspected and still others arise from the impact that the intelligent pigging operation has on normal production operations upstream of the pipeline,
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- (3 more...)
ABSTRACT portable pig launcher, Kuparuk, pigging ABSTRACT Many oil fields on the North Slope were built without pig launchers and receivers in production gathering lines. Maintenance cleaning and smart pigging of selected lines have become necessary as the field matures. This paper discusses the field background, design considerations, and test strategy for a portable pig launcher designed to ease the task of pigging multiple lines with a single facility INTRODUCTION The Kuparuk oil field is located on the North Slope of Alaska, approximately 40 miles west of Prudhoe Bay. The reservoir produces approximately 300,000 barrels of crude oil each day (47,690 kLOPD) and 353,000 BWPD (56,102 kLWPD). The extremely cold temperatures can make even comparatively simple operations complex. The Kuparuk crude oil is produced from 42 drill sites throughout the field, Oil produced at individual wells are manifolded at each drill site into a single gathering line, These lines flow cross country and join the flows from multiple drill sites in larger diameter gathering lines, which then flow to the Central Processing Facilities (CPFS) for separation of the oil, water, and gas. The piping arrangement is a trunk-and-lateral design. Eight-inch (203 mm) to sixteen- inch (406 mm) nominal diameter piping from an individual drill site flows into twenty-four inch (61O mm) cross - country gathering lines. Thus, production from drill sites closer to the CPFS are merged with production from drill sites farther from the CPFS. The lines that carry the crude were constructed in different expansions. Therefore the pipeline layout is somewhat disorderly. They branch, interconnect, and change size as they flow crude from the production sites to the processing facilities. The original piping design called for pig launchers and receivers, but these were omitted from the as-built facilities due to shipping and delivery time constraints. As such, it was not possible to run cleaning pigs through the production lines. Likewise, it was not possible to run inspection vehicles through the pipelines. Kuparuk cross-country pipelines run above ground on steel vertical support members (VSMS). The pipe runs incorporate road crossings and Caribou crossings, where the piping passes below ground through steel casings. These areas cannot be inspected by conventional means unless they are excavated. Smart pigging is a method which would allow complete inspection of the internal and external condition of the piping without excavation. The trunk-and-lateral layout of the pipelines means that capital costs for conventional pigging facilities would be exorbitant. A field survey indicated that 116 sites would be required to pig only those lines that exceed 1 mile in length. Corrosion studies indicate that the primary mode of corrosion in these lines involves an under-deposit corrosion mechanism and so pigging must be evaluated as a method of corrosion control. FACILITY DESIGN CONSIDERATIONS A decision was made to pig two of the lines as a pilot test. Both of the lines in question showed elevated coupon rates, and spot inspection with ultrasonic and radiographic methods confirmed these lines as good candidates for pigging and corrosion mitigation tests. The prc}gram is investigating solids accumulation and composition, the application of corrosion inhibitors in conjunction with maintenance cleaning of the lines, the efficiency of corrosion inhibitor injection without pigging, and the internal and external condition of both the lines with several types of instrumented pigs. Because of the high capital cost of conventional facilities, portable pigging facilities were considered a practical approach to the problem. How