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Collaborating Authors
annular pressure drilling
ABSTRACT Because of the reduced difference between fracture and pore pressure gradients inherent in deepwater drilling, gas influx during a kick must be limited to much lower volumes than on land or in shallow water. To do this, instruments capable of detecting a kick at a very early stage are needed. Using a recently developed computer program capable of modeling a kicking well, the transient behavior of several well parameters was investigated to determine which parameters are most indicative of a kick and what sensitivity is desirable for instrumentation to measure these parameters. Results show that instrumentation to detect changes in return mud flow rate offers the greatest potential. Pit volume and standpipe pressure instruments can provide valuable backup detection capability, provided they can be made sufficiently sensitive. Standpipe pressure instruments have potential advantages for floating drilling operations, since they should be unaffected by vessel motion. Desired sensitivity levels, based on the computer analysis, are presented for each type of instrument. INTRODUCTION Increasing water depth reduces the difference between the mud weight required to balance formation pore pressures and that which will result in formation fracture. Figure 1 illustrates this point at the seat of a 3500-ft surface casing string. If a 0.5-lb/gal margin is provided relative to both the fracture gradient and the pore pressure gradient (seawater gradient assumed), the range of allowable mud weights is substantially reduced as water depth increases. Another way of illustrating the effect of increasing water depth is to consider the "critical kick size". This is the maximum gas influx that can be contained within a shut-in well without fracturing the rock at the casing seat. Influxes greater than this size will cause an underground blowout when shut in. Figure 2 shows the critical kick size as a function of water depth for kicks taken while drilling a 12 ¼-in hole 5000 ft below a 3500-ft surface casing string. Mud weights of 9.5 and 10 lb/gal and under balance conditions of 0.25 and 0.5 lb/gal are considered. While kicks of 150 to 250 bbl are necessary to produce casing seat failure on land, in 5000 ft of water the critical kick size ranges from zero to 100 bbl for the conditions assumed in this example. This analysis shows that there is a definite incentive in deepwater drilling operations to detect and control kicks at an early stage of their evolution. The accuracy, sensitivity, and reliability of the drilling instrumentation are key elements in determining at what stage a kick will be detected and controlled by the drilling personnel. We have investigated the time-dependent evolution of kicks under a variety of assumed conditions to better define what types of instrumentation are useful for early kick detection and what levels of accuracy and sensitivity are desirable. In this work we utilized a recently developed computer program that models the transient behavior of a kicking well.
- Research Report > New Finding (0.89)
- Research Report > Experimental Study (0.75)
ABSTRACT During the summer of 1977, the wreckage of the ZAPATA TOPPER III was dismantled down to a water depth of 85 ft. to provide safe navigation for marine craft transit in the vicinity of the wreck. The TOPPER III capsized in March 1975 in a blow-out while standing on location in 196 ft. of water. This paper describes (1) the events that resulted in the capsizing, (2) the process of obtaining governmental approvals for a debris clearance operation and (3) the details of the clearance operation conducted in August-September 1977. This operation involved the use of explosive cutting charges and was accomplished by the close cooperation and employment of the combined technical capabilities of Zapata Off-Shore Company, Oceaneering International, Inc., Murphy Pacific Marine Salvage and Hancock Industries. The descriptions of the diving techniques and explosive cutting charges employed in the operation can serve as a reference for future clearance, debris removal or salvage operations of other drilling rigs or marine craft which suffer severe casualties in accident situations. The paper describes the types of explosives and shape forms used in cutting typical drilling rig structures. The paper also describes the use of underwater burning techniques used on structural stiffness, piping, electrical cableways and other features of the wreck that were not cut with explosives. The method used to tap and remove the oil from the drilling rigs fuel tanks is described in the paper to serve as a model in similar situations as a means to remove oil from an underwater wreck with no spillage of oil or marine pollution. INTRODUCTION The TOPPER III, a 300 ft. water depth capability Marathon LeTourneau built mobile offshore jack-up drilling unit, was drilling an exploratory well on March 19, 1975 at a 196 ft. water depth location at an OCS site located 89 miles southeast of Galveston, Texas (Figure 1). When an undetected and unexpectedly shallow gas zone was drilled into, an uncontrollable blowout was experienced which subsequently eroded away the sea floor foundation around the two stern legs of the three legged jack-up unit. This massive erosion of the sea bed as a result of high velocity unwelling and gas flow caused critical subsidence of the two stern legs of the TOPPER III in a manner that eventually capsized the entire upper hull of the drilling unit and caused the unit to sink within only 12 hours after the blow-out started. The entire crew of the TOPPER III was safely evacuated from the rig after all possible efforts to control the exploratory well blowout failed and before the rig capsized and sank. INITIAL DIVING SURVEY After the shallow gas zone discharged itself and the blowout crater bridged over, a diving survey was planned and executed. Zapata retained the diving services of Oceaneering International, Inc. to perform the underwater inspection survey of the TOPPER III wreckage and to provide electronic instrumentation for the remaining portion of the survey.
This paper describes a unique application of polymers in a blowout of a high-capacity gas well in the Middle East. The polymers effectively assisted in controlling the blowout by polymers effectively assisted in controlling the blowout by filling up cavities in the formation and diverting or preventing hydrocarbons from entering the wellbore. Although the well was not brought under control completely, the material did reduce the flow rate enough to extinguish the flame. Introduction Blowouts in high-capacity formations require high pump and capture rates for control, even when subsurface communication between the relief hole(s) and the uncontrolled well is good. Control fluids are carried out of the hole by high-velocity flow. A hydrostatic head large enough to overbalance the formation pressure cannot be obtained. Hole enlargement also creates difficulty by retaining control fluids or by causing their dilution with formation fluids before they can take effect. Polymers can be used effectively to reduce the flow rate from the uncontrolled well so that control fluids kept in the hole can control the well. Also, polymers can be used to fill enlarged hole spots and alleviate control-fluid retention or dilution downhole. Using polymers for blowout control evolved during a lengthy control effort of an offshore-Dubai platform development well. The well blew out on July 19, 1975, and flowed uncontrolled until Feb. 24, 1976. Four attempts were made to control the well by directly pumping sea water and mud before using polymers during the fifth attempt. The blowout was not controlled completely, but the gas flow rate was reduced and the flame actually was extinguished. The supply of the most effective polymer became exhausted, so the control operation was terminated. Plans for the next attempt included extensive use Plans for the next attempt included extensive use of polymers; however, the hole was bridged and gas flow ceased, making further control measures unnecessary. Polymers will not be the key to well control every time, but they showed great promise in the Dubai situation and should be a valuable aid to control blowouts. The Blowout The Fateh field L-3 development well had reached 4,180 ft (515 ft below the Asmari gas-water contact) when the kick occurred. A 30-in. conductor had been driven to refusal at 450 ft and a full string of 20-in. casing was cemented at 1,310 ft. The kick control effort was terminated and the rig abandoned when gas broke around the 20-in. shoe and bubbled up under the platform. Eight days after the blowout, the gas ignited and in 2 weeks the rig and platform disappeared beneath the Arabian Gulf. The Asmari limestone formation in the Fateh field has a total thickness of about 540 ft, with a 115-ft gas column at Well L-3. The upper part of the Asmari is vuggy and fractured with permeabilities of several hundred millidarcies. The lower portion of the Asmari is shaly and relatively tight. The entire section of the Asmari gas and water columns was open to the 17 1/2-in. wellbore, resulting in a high-rate gas flow with an indeterminable amount of entrained water. Control Effort Before the well ignited, efforts were made to move barges up to the platform so that surface control measures could be tried. JPT P. 705
- Asia > Middle East > UAE > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Nosrat Field > Sarvak Formation (0.99)
- Asia > Middle East > UAE > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Nosrat Field > Ilam Formation (0.99)
- Asia > Middle East > UAE > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Nosrat Field > Faraghon Formation (0.99)
- (4 more...)
ABSTRACT Well control training is a vital need in the proper conduct of oil and gas discovery and development activities. Potential risks while drilling are examined and statistics are shown on the low frequency of occurrence on major well control problems. Several elements are reviewed which collectively form an effective well control system. Training is emphasized and Exxon' s new well control training facility in the Houston area is described. Finally, the main content and impact of recent OCS regulations on drilling are assessed. It is concluded that effective training program are essential to keeping drilling risks controlled and minimized. INTRODUCTION Although blowouts occur rarely for both Exxon and industry, it is our goal to eliminate them. A well out of control poses a very serious threat to people, equipment and the environment. On the other hand, drilling wells has always been a difficult undertaking, and a certain amount of risk is inherently involved. We all share in this risk-taking, and our common aim is to develop new reserves while keeping this drilling risk controlled and minimized. This paper addresses well control generally with special emphasis on training (Figure 1). Included in the paper is a discussion of drilling risks; an outline of the components of an effective well control system; emphasis on the importance of training, including a review of Exxon's new Friendswood training facility; and a brief appraisal of the status of regulatory affairs in this important area. DRILLING RISKS First, let's examine drilling risks. A good starting place is to survey what levels of exposure are involved. Figure 2 assesses the range of exposure for investment, safety of personnel, and, pollution on both land and offshore operations. Generally, there is less exposure in land operations than offshore, except where the possibility of uncontrolled sour gas production could create a major hazard in the area near the well. Investments on land rigs are relatively low, in the range of $2 to $5MM, depending on the rig size. An exception, however, is where land rigs are modified for special application such as the North Slope of Alaska. Arctic rig investments reach $8-10MM. Offshore, however, investment exposure is substantially higher. Jackup rigs now cost between $25MM and $30MM and large semisubmersibles and drillships are about double this amount. Exxon's new semisubmersible rig, the Alaskan Star, cost $50MM. Where platform drilling is involved, the additional investments for platforms and wells can be very large. Exxon?s recent platform installation in 850 feet of water offshore California approached $80MM, excluding wells and facilities. Personnel levels on land rigs are relatively low. Rig operators and service company employees on location usually include less than 10 personnel. In contrast, offshore activities require from 25 to 75 employees, and infrequently may run as high as 100 personnel.
- North America > United States > California (0.49)
- North America > United States > Texas (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.48)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Equipment (1.00)
This paper covers various drilling problems and completion techniques in the 9,000-acre Sholom Alechem field of Stephens and Carter counties, Oklahoma. Oil and gas production is from the Sycamore formation at 8,000 ft deep. Although normally a limestone, this Mississippian age reservoir is a calcareous sandstone at Sholom Alechem. Introduction The cumulative crude oil production per acre or per acre-foot in Stephens and Carter counties is as great as any other sizeable area in Oklahoma. Recent Sycamore sandstone development in a previously neglected formation, the Sholom Alechem field of Stephens and Carter counties (Fig. 1), has added significantly to this cumulative production. production. The Sholom Alechem field (Fig. 2) is located in the eastern half of Township 1 South, Range 4 West, and Township 1 North, Range 4 West, Stephens County, and in the western part of Township 1 South, Range 3 West, Carter County. The Sycamore sandstone development, begun in 1972, includes 110 wells on an 80-acre spacing, involves 26 operators, and essentially has been completed. The Sycamore formation is found from 7,500 to 8,200 ft. Current daily production is 3,100 bbl and a total of 6,860,000 bbl has been produced from the Sycamore as of Oct. 31, 1976. Ultimate production is expected to range from 10 to 12 million bbl of oil and 75 million Mcf of casinghead gas. History Oil originally was found in this area by Humble Oil and Refining Co. in 1923. The discovery well was the Jennings No. 1, located in the SW SW of Section 28-T1S-R3W, Carter County. The producing formation was the Pennsylvanian Deese sand at 3,400 ft. Early development was slow because the wells were low-volume producers and remained slow in the 1930's and 1940's, producers and remained slow in the 1930's and 1940's, because of the Depression and World War II. In Aug. 1947, Stanolind Oil and Gas Co. discovered Springer sand in their Sims No. 1 located in the NE SE of Section 2-T1S-R4W, Stephens County. The well produced 118 B/D of low-gravity oil from 4,800 ft. Rapid development continued for the next 5 years, with additional Deese and Springer sands discovered and developed. Much of this development was done on a 10-acre spacing. During the next 15 years, shallow development was limited to drilling a few edge and infill wells, plus beginning several secondary recovery projects, primarily waterfloods of the Sims and Deese projects, primarily waterfloods of the Sims and Deese sands. JPT P. 35
- North America > United States > Oklahoma > Oklahoma County (0.70)
- North America > United States > Oklahoma > Carter County (0.60)
Abstract Low-porosity, low-permeability zones are being successfully stimulated in the Appalachian Area by a technique termed Mini-Massive Frac. This technique combines several techniques commonly used to increase fracturing efficiency and improve results. These include methods to:Control fluid loss into hairline fractures. Control fluid loss into matrixpermeability. Control fracture height. Achieve a deeply penetrating, packed fracture. Use of the technique has provided productivity increases many times greater than conventional treatments, and these are proving to be sustained increases. This paper describes the mini-massive frac and its application to low-porosity, low permeability zones in other areas. Introduction In the 1960's, a team of researchers working under the direction of MIT geologist William Brace discovered that as rock approaches its breaking point, a myriad of tiny cracks form in certain point, a myriad of tiny cracks form in certain direction. This phenomenon is called "dilatancy" and it has been theorized that when dilatancy occurs the rock strength paradoxically increases and the rock resists fracturing temporarily. In crustal rocks, ground water seeping into the tiny cracks, however, will eventually weaken the rock and cause it to rupture. It is believed that dilatancy also occurs during hydraulic fracturing of underground formations. (We have known for years that all subsurface rocks are triaxially loaded; that is, they have a force exerted upon them by the overlaying formations. This vertical force or stress imposed on the rock causes a horizontal stress to exist within the rock system. If the rock were not confined within the earth, this vertical force would express itself by causing the rock to deform or expand its lateral dimensions. When pressure is applied from within such a system, the rock ruptures or fractures in a plane perpendicular to the least amount of stress on the system. These stresses will control the direction of the fracture and determine whether the fracture plane will be horizontal, vertical or inclined.) During a fracturing treatment pressure is applied to a rock formation. As the rock approaches its breaking point due to the applied pressure, a myriad of tiny cracks form. Dilatancy pressure, a myriad of tiny cracks form. Dilatancy then continues to occur along the leading edge of the fracture as it progresses outward into the formation. This theory of dilatancy during hydraulic fracturing can be used to explain several phenomena observed from past fracturing treatments. phenomena observed from past fracturing treatments. Some of these are:Premature screenout in very low permeability formations. Failure of the fracture to penetrate as far as calculated. Failure of the well productivity to achieve predicted folds of increase. The explanation simply is that a portion of the frac fluid leaks off into the myriad of tiny cracks and the natural fractures encountered. The fluid that leaks off is not available for fracture extension. This leak off of fluids can be controlled with high viscosity fluids, temporary fluid-loss additives, etc. But when the frac job is complete, the cracks and natural fractures close. Another way to control this leak off is with the use of 100 mesh sand as a spearhead. The diameter of a grain of 100 mesh is .0059 inch while a grain of 20–40 frac sand has a diameter of 0.033 inch.
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.34)
Introduction In the past 10 years there has been a radical change in laws governing the oil and gas industry. These changes are due to environmental emphasis and public support. We have been reluctant to change from the regular way of doing things. The nature of the industry is exploration in low-population, inaccessible areas where it was not considered necessary to take adequate precautions. Oil and gas were and still are a low yield for investors; economy is demanded on every front. Ten years ago you were lucky if you received $3.00 a barrel for your oil, and 20 cents a thousand for your gas. The economic squeeze has not been eliminated; inflation has taken its toll; the cost of material, machinery, equipment and personnel, life of well contracts, depletion of the more prolific shallow reserves still does not make oil and gas the most appealing investment available. Many states as well as the national energy policy writes us off as a depleted industry. States, if not by choice, also downgrade our importance by national pressures. The oil and gas industry cannot be written off; we have a very demanding and important part to play in the energy picture during our lifetimes and that of our children. There is no utopian cheap fuel of any kind in history. Drilling and producing smaller wells, deeper wells, and enhanced recovery are expensive. With federal regulations on all energy industry, we will continue to be competitive, and the leader in energy resources. Some of you remember the formation of the Environmental Protection Agency; their first regulations were directed toward Protection Agency; their first regulations were directed toward oil spills. I asked at one meeting, "Why are you directing your efforts toward the oil industry while other, more hazardous and toxic materials are prevalent?" The response was that oil spills could be detected with just a rainbow showing up on the water; therefore, they are the easiest pollutant to detect. The EPA would begin with oil and expand to other areas. The Santa Barbara Channel and the Michigan gas blowout received national attention and had a great influence on the various state and federal laws. In West Virginia a salt-water pollution problem had a significant effect on their laws. pollution problem had a significant effect on their laws. It is interesting to note as you are reading the various state laws the emphasis that is placed on a single accident or problem, and what the state feels is primarily important in that problem, and what the state feels is primarily important in that specific state. It is very apparent that all state laws continually are being upgraded to meet federal demands. An excellent example is the EPA. Their regulations allow a state so much time to upgrade their regulations to meet their minimum requirements, or they will be the regulator. They, along with so many federal agencies, have matching money for an assistance program to aid the states in inventories, policing and reporting. One of the basic requirements is for the state's highest elected official to pledge the state to meet their requirements. In this study we will review the oil and gas laws of Kentucky, Virginia, West Virginia, Pennsylvania, New York, Maryland, Michigan, Ohio, and Tennessee. It is interesting to note in every case that the regulatory agency for oil and gas is a subordinate of some other agency (except Tennessee). REGISTRATION In Kentucky there is no defined process for registration. They do require an affidavit of transfer of ownership, and also require bonding by the new owner. In Virginia all drillers, owners, and operators must register. West Virginia requires all owners to register with the department. In case of a corporation or out-of-state owner, a responsible agent who is a resident must be named, and any change in agents must be reported within 5 days.
- North America > United States > Virginia (1.00)
- North America > United States > West Virginia (0.76)
- North America > United States > California > Santa Barbara Channel (0.24)
- Law (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Brown Field > Wichita-Albany Formation (0.98)
- North America > United States > California > Santa Barbara Channel (0.89)
- North America > Canada > Ontario > Michigan Basin (0.89)
Circulating Out Gas Kicks In Deepwater Floating Drilling Operations
Ilfrey, W.T. (Exxon Production Research Company) | Alexander, C.H. (Exxon Production Research Company) | Neath, R.A. (Exxon Production Research Company) | Tannich, J.D. (Exxon Production Research Company) | Eckel, J.R. (Exxon Production Research Company)
Abstract Friction and hydrostatic effects in the long, small-diameter choke line used in deepwater floating drilling operations can cause large and rapid wellbore pressure changes when normal techniques are used for pressure changes when normal techniques are used for circulating out a gas kick. These changes can be sufficient to cause secondary kicks or loss of returns. Use of easily collected additional onsite test information and minor modifications in conventional wellcontrol equipment and procedures can minimize or eliminate these problems. Introduction Conventional floating drilling operations use a relatively small-diameter choke line to connect the ocean floor blowout preventers to the choke manifold aboard the drill vessel. Frictional and hydrostatic effects resulting from use of the choke line complicate the conventional process of circulating out a gas kick. The usual process of circulating out a gas kick described by Goins, and generally used in industry, involves:Shutting-in the well after a kick is detected. Recording shut-in stabilized drill-pipe and annulus pressures. Establishing a constant kick pump-out rate and the related constant dynamic drill-pipe pressure, while holding the mud weight and the annulus pressure constant at the original shut-in value, through choke manipulation. Circulating out the gas kick at this constant pump rate while holding bottom-hole pressure constant by choke manipulation, to either increase or decrease annulus pressure as necessary to produce the required drill-pipe pressure. If the mud used to circulate out the kick is original weight mud, the procedure is known as the "Driller's Method." In this method, drill-pipe pressure is held constant throughout the process. pressure is held constant throughout the process. If heavier mud is introduced during the circulation, the procedure must be modified and drill-pipe pressure must procedure must be modified and drill-pipe pressure must be decreased systematically as the heavy mud fills the drill pipe. Use of the procedure for establishing dynamic drill-pipe pressure causes the initial pressure drop resulting from friction in the annulus to be added to the bottom-hole pressure. For wells with blowout preventers (BOPS) at the surface or for shallow-water preventers (BOPS) at the surface or for shallow-water floating drilling, this annular pressure drop is negligible at usual pump-out rates. As choke-line length increases, however, the initial friction pressure drop in the choke line can be an appreciable addition to both casing-seat and bottom-hole pressures. This could be a cause of formation fracturing at the casing seat. When the gas kick reaches the base of the choke line and displaces mud in the choke line, or later when mud displaces gas in the choke line, rapid hydrostatic pressure changes can occur. These changes will cause pressure changes can occur. These changes will cause (respectively) either a rapid decrease or a rapid increase in drill-pipe pressure that must be compensated by equally rapid increases or decreases in annulus pressure through choke manipulation to hold bottom-hole pressure constant. Even if a circulation rate as low as 2 bbl/min is used, the required rates of annulus pressure change may exceed the ability of the choke and operator to react. The operator may either fail to detect drill-pipe pressure changes in a timely fashion or be unable to pressure changes in a timely fashion or be unable to manipulate the choke quickly enough to compensate for the rapidity of those changes and thus fail to prevent a secondary kick or formation fracturing. These changes in pressure are the principal reason the "Driller's Method" is recommended for deepwater well control. Drill-pipe pressure decreases required when heavier mud is being introduced may be impossible to distinguish from drill-pipe pressure decreases that signal arrival of gas at the sea floor, if kick size and open-hole annulus capacity are not known.
Abstract Dynamic laboratory fluid loss testing of foam water base fluids on low-permeability, thin sandstone core wafers has established fluid loss coefficient values as well as defining some of the variables that control fluid leakoff from a foam. Liquid additives that can reduce fluid leakoff through the core wafers also have been developed. These additives reduce fluid leakoff by threefold or more in concentrations as low as 50 ppm of the water volume. Introduction Water and nitrogen foam for fracture stimulation has found acceptance due to the low water content of the treatment fluid and the excellent cleanup effects of nitrogen gas. Foam fracturing treatments have been used extensively in shallow, low-pressure gas producing formations and have in many cases producing formations and have in many cases outperformed gelled water fracture treatments in stimulating these formations. Significant gas reserves are contained in low-permeability sandstone formations. Tests of foam fluid leakoff through low-permeability sandstone core wafers were necessary to furnish data for designing the optimum fracture treatment for these formations. This report presents the fluid loss coefficients for foam on low-permeability sandstones as well as discussing some of the factors that influence foam leakoff. Until now, the addition of long chain polymers to the water phase of the foam has been the only method of reducing foam fluid leakoff. This paper discusses new liquid additives that have been tested and have shown the potential of controlling fluid leakoff without adding long chain polymers to the foam that may leave a residue in the formation. Summary Of the naturally occurring factors tested, only the permeability of the core wafer and the test pressure differential had any significant effect on pressure differential had any significant effect on the fluid leakoff of the foam. Foam quality and foamer concentration did not appear to have an effect on the fluid leakoff rate. The addition of from 50 to 500 ppm of selected liquid leakoff additives will reduce the liquid and gas leakoff rates by a factor of two- to fivefold. These additives appear to act on the gas in the foam to alter bubble properties. The performance of these additives is approximately comparable to the leakoff control obtained with a 15-lb concentration of hydroxy-ethyl cellulose per 1,000 gal of water. The cost of these organic additives is about 1/50th of the cost of polymer addition. RESULTS AND DISCUSSION Apparatus and Test Procedure The test apparatus used for all the foam tests is shown schematically in Fig. 1. A test stand supports all the cell-related equipment in close proximity to minimize friction or shear in the piping proximity to minimize friction or shear in the piping system. Glass-windowed viewing chambers are included to check the general foam condition before the fluid passes into the test cell. The visual inspection of passes into the test cell. The visual inspection of the foam determines if all liquid and gas are tied up in foam and gauges bubble size and shape, which are an indication of the condition of the foam. Normally, the most stable foams have reasonably uniform small bubbles with no large pockets of gas. The basic design of the body of the test cell is similar to the API baroid high temperature, high pressure, fluid loss cell for measuring fluid loss on muds and fracture fluids. The test cell is constructed (Fig. 2) to allow flow of the foam over the face of the wafer and uniform contact of the foam on the surface of the wafer. The inverted funnel shown in Fig. 2 spreads the foam over the wafer to insure uniform contact of the surface with the foam, thus preventing a collection of water or gas on the surface of the wafer.
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract On March 24, 1976, Tenneco Oil Company experienced a blowout in the West Cameron 165 Field. West Cameron 165 Well No. 3, a single-sell platform installation, was blowing out of control. By April 11, 1976, the casing strings and the platform had subsided beneath the surface of the Gulf of Mexico, leaving a huge gas boil approximately 100 feet in diameter as the only remaining visual evidence of the blowout. Prior to drilling the relief well to total depth, calculations were made to predict the anticipated bottom hole and surface injection pressures, injection volumes, and injection breakthrough times. These calculations, presented in a graphical format, would serve as guidelines during the actual injection operation. In addition, new methods were employed for utilizing the Hewlett-Packard Quartz Pressure System and side scan sonar equipment to determine if the blowout well was flowing underground and/or beneath the surface of the water. Introduction West Cameron Block 165 is located 32 miles southwest of Cameron, Louisiana, in a water depth of 48 feet. The field was developed by six single-well platform installations. All six wells were completed in the only productive sand in the field, the K-2 Sand. Prior to blowing out, Well No. 3 was the best producer in the field with a flow rate of 13 MMCFD, 90 BCPD, and with a flowing tubing pressure of 2900 psig. Well No. 3 was drilled essentially as a straight hole during November of 1969 and completed in the K-2 Sand with subsea perforations at 9620–26 feet and 9638–57 feet. On March 23, 1976, all six single-sell platform installations in the field were manually shut-in to install new production equipment on the No. 1 Platform, the central gathering platform for this Platform, the central gathering platform for this field. At 7:00 A.M., on March 24, 1976, gas was discovered escaping from around the bradenhead flange of West Cameron 165 Well No. 3. Initial inspection of the area indicated that the flow was occurring primarily between the bradenhead flange; however, gas bubbles were also seen around the legs of the platform. Within two hours, the bradenhead bolts were flow cut and the tree was blown off the bradenhead flange. Well No. 3 was out of control; blowing gas, mud, and sand. Upon being notified of the problem on the morning of March 24, 1976, Tenneco oil Company assembled its "Spill Contingency Task Force". Since the structure of the "Spill Contingency Task Force" was organized in advance, this work force immediately determined that a relief well would be required and began planning strategy to bring the well under control. Subseqnently, this task force became known as the "Blowout Team". The Blowout Team met at least once a day to make recommendations, coordinate the planning, and oversee the execution of various blowout operations. On May 9, 1976, just 47 days after the blowout occurred, the dedicated work of this task force and many people within the Industry was culminated as Well No. 3 was successfully killed. Due to the limited scope of this paper, the actions of the entire blowout operation cannot be detailed. However, the use of the computer and other special tools for monitoring a gas well blowout during the kill operation are discussed herein. A second paper deals specifically with the relief well drilling operations, kill equipment, and the injection operation. INJECTION PRESSURES, VOLUMES, AND TIMES Prior to drilling the relief well (Well No. 12) to total depth, it was necessary that the injection operation be fully understood by all involved. Since Well No. 3 was drilled essentially as a straight hole during 1969 and only single shot directional surveys were taken, then the exact bottom hole location of Well No. 3 was not known.
- North America > United States > Louisiana (0.90)
- North America > United States > Texas (0.68)