High Pressure Coiled Tubing Job Prepares Gulf Coast Well
Abstract: This case history paper presents the details of the role played by coiled tubing in returning a high-profile, Gulf of Mexico oil/gas well to production after the well had to be shut in due to excessive sand production. The paper presents the following events/conditions:The well could not be injected into in several attempts up to 9,300 psi. Since the well had produced sand, operators suspected that a sand plug existed.The well was completed with 4 1/2", 15.1# production tubing.Coiled tubing performed offline w… Show more
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As upstream oil and gas exploration and production companies search for new opportunities, much deeper wells are being drilled and completed. In addition to greater depths, an increasing number of wells are being drilled and completed in much more hostile downhole environments. These very complex wells are frequently drilled in frontier areas around the world, including the Western and Northern Canadian foothills and coastal areas. Where pressures exceed 10,000 psi (69 MPa) and temperatures surpass 300°F (149°C), wells are generally termed High-Pressure/High-Temperature (HPHT) completions. The stresses resulting from the combination of high axial loads and pressure differentials begin encroaching on materials limitations of standard subsurface equipment. This paper provides an overview of an engineering design methodology that can be used during the planning of deep, difficult, or complex wells. The importance of numerous design considerations and realistic, clearly defined load cases will be emphasized. High temperatures cause the well to operate with either significant pipe movement, or high compressional loads at the packer, particularly when these high temperatures are combined with higher operating pressures. The increased well depths, usually with accompanying deviations from vertical, also increase mechanical and fluid friction. These situations require a rigorous engineering analysis with the aid of modern thermal and stress analysis software. Traditional uniaxial and biaxial working stress designs are convenient and usually adequate for shallower, lower temperature/pressure wells. However, the severe conditions considered within this paper require state-of-the-art triaxial design software. Examples within the paper will demonstrate how the results of these simulations can be used for hostile environment tubular selection, including discussion of the importance to properly select and test the tubular connections. Many failures have resulted from brittle fracture or fatigue rather than yield, because the tendency for the designer is to choose higher yield strength materials that are inherently less ductile and more prone to hydrogen embrittlement. To avoid this, it is better to push the limits of lower strength, ductile materials, which in turn challenges the typical design safety factors. This challenge has lead some major oil companies to develop and use risk based tubular design processes. Background The completion of HPHT wells have unique design challenges that require rigorous engineering approaches, analyses, and planning. Although the industry has been working with HPHT wells for a number of years, the application of appropriate technology in several areas is still evolving as more operators begin to pursue these horizons. Because of encroachment on some of the generally accepted technology norms and boundaries, some risk will need to be assumed while expanding these boundaries through improved equipment designs, altered or more rigorous engineering based procedures, or development of new technologies. Generally the design philosophy begins with the expansion of available field proven technology, which is preferred over completely new designs that have not been successfully tested in actual field applications. At the outset of an HPHT project, the overall completion design objective should achieve the well's production target with an acceptable level of risk.
As upstream oil and gas exploration and production companies search for new opportunities, much deeper wells are being drilled and completed. In addition to greater depths, an increasing number of wells are being drilled and completed in much more hostile downhole environments. These very complex wells are frequently drilled in frontier areas around the world, including the Western and Northern Canadian foothills and coastal areas. Where pressures exceed 10,000 psi (69 MPa) and temperatures surpass 300°F (149°C), wells are generally termed High-Pressure/High-Temperature (HPHT) completions. The stresses resulting from the combination of high axial loads and pressure differentials begin encroaching on materials limitations of standard subsurface equipment. This paper provides an overview of an engineering design methodology that can be used during the planning of deep, difficult, or complex wells. The importance of numerous design considerations and realistic, clearly defined load cases will be emphasized. High temperatures cause the well to operate with either significant pipe movement, or high compressional loads at the packer, particularly when these high temperatures are combined with higher operating pressures. The increased well depths, usually with accompanying deviations from vertical, also increase mechanical and fluid friction. These situations require a rigorous engineering analysis with the aid of modern thermal and stress analysis software. Traditional uniaxial and biaxial working stress designs are convenient and usually adequate for shallower, lower temperature/pressure wells. However, the severe conditions considered within this paper require state-of-the-art triaxial design software. Examples within the paper will demonstrate how the results of these simulations can be used for hostile environment tubular selection, including discussion of the importance to properly select and test the tubular connections. Many failures have resulted from brittle fracture or fatigue rather than yield, because the tendency for the designer is to choose higher yield strength materials that are inherently less ductile and more prone to hydrogen embrittlement. To avoid this, it is better to push the limits of lower strength, ductile materials, which in turn challenges the typical design safety factors. This challenge has lead some major oil companies to develop and use risk based tubular design processes. Background The completion of HPHT wells have unique design challenges that require rigorous engineering approaches, analyses, and planning. Although the industry has been working with HPHT wells for a number of years, the application of appropriate technology in several areas is still evolving as more operators begin to pursue these horizons. Because of encroachment on some of the generally accepted technology norms and boundaries, some risk will need to be assumed while expanding these boundaries through improved equipment designs, altered or more rigorous engineering based procedures, or development of new technologies. Generally the design philosophy begins with the expansion of available field proven technology, which is preferred over completely new designs that have not been successfully tested in actual field applications. At the outset of an HPHT project, the overall completion design objective should achieve the well's production target with an acceptable level of risk.
As producing companies search for significant hydrocarbon resources, it has become necessary to pursue opportunities in frontier geologic horizons and geographic locations. This pursuit frequently results in encountering High Pressure – High Temperature (HP/HT) environments. The petroleum industry defines HP/HT wells as those exceeding 10,000 psi and 300°F. Several companies have drilled into HP/HT horizons in the California San Joaquin basin over the past 30 years, but generally operations were halted due to equipment limitations or due to limited hydrocarbon indications. In late 1998, a significant gas flow was identified from the Temblor formation at depths below 17,100 ft, with geologic information indicating a potential Temblor sand gross thickness of up to 3600 ft.. The pressure design basis for subsequent wells assumed an estimated equivalent pore pressure of 16.9 ppg. This information and other producing conditions, indicated potential bottomhole conditions of 425°F and 18,000 psi. Produced fluids also indicated the presence of hydrogen sulphide (H2S), which, at these pressures, dictate sour service metallurgical specifications. These potential extreme well conditions required very detailed completion engineering design, equipment qualification, rigorous planning, and precise field execution to achieve successful well completions. This paper will detail and discuss the well completion design basis and issues; equipment/perforating limitations and qualification tests, tubular stress and loading analyses, high-density completion brine usage, and actual field operational experiences. Numerous contingencies were planned in detail, some of which had to be implemented. The most significant contingency operation was a high pressure coiled tubing milling operation to clean out 2500 ft of formation and perforating debris, which plugged the tubing string. Background The wells discussed in this paper are located approximately 50 miles northwest of Bakersfield, California in the East Lost Hills Field. The East Lost Hills Field is situated in the southern end of the San Joaquin Basin, which began evolving during late Cretaceous and early Miocene time. The basin is primarily bounded to the North, East, and South by the granitic rocks of the Sierra Batholith and Foothills belt, and to the west by the San Andreas Fault. The primary objective of this drilling and appraisal program is the lower Miocene Temblor section (Zemorrian to Saucesian), which is a 3600 ft thick succession of interbedded sandstones and shales of bathyal origin. Wells thus far have reached depths between 17,400 ft and 21,700 ft. Pore pressure gradients at this depth are approximately 0.88 psi/ft, and reservoir temperatures are between 350–385°F. The first well was drilled in 1998 and penetrated the Temblor sand section; however, upon reaching the zone of interest, unforeseen pore pressures resulted in an uncontrolled flow from the well. The surface flowing information obtained from this well formed the basis for future well designs and equipment qualification requirements. Assumptions for the worst case reservoir pressures and temperatures of a well drilled to a total depth of 20,000 ft had to be made for the future well completion designs. The resultant maximums were extrapolated to be 18,000 psi and 425°F. These combined conditions, together with the fact that hydrogen sulphide (H2S) and carbon dioxide (CO2) were present in the well effluents, approach the operating boundaries and limitations of many tubulars and completion equipment.
As producing companies search for significant hydrocarbon resources, it has become necessary to pursue opportunities in frontier geologic horizons and geographic locations. This pursuit frequently results in encountering high-pressure/high-temperature (HP/HT) environments. The petroleum industry defines HP/HT wells as those exceeding 10,000 psi and 300°F.Several companies have drilled into HP/HT horizons in the California San Joaquin basin in the past 30 years, but operations were generally halted because of equipment limitations or limited hydrocarbon indications. In late 1998, a significant gas flow was identified from the Temblor formation at depths lower than 17,100 ft, with geologic information indicating a potential Temblor sand gross thickness of up to 3,600 ft. The pressure design basis for subsequent wells assumed an estimated equivalent pore pressure of 16.9 lbm/gal. This information and other producing conditions indicated a potential bottomhole environment of 425°F and 18,000 psi. Produced fluids also indicated the presence of hydrogen sulfide (H 2 S), which, at these pressures, dictates sour service metallurgical specifications.These potential, extreme well conditions require a very detailed completion engineering design, equipment qualification, rigorous planning, and precise field execution to achieve successful well completions. This paper details and discusses the well completion design basis and issues, equipment/perforating limitations and qualification tests, tubular stress and loading analyses, high-density completion-brine usage, and actual field operational experiences.Numerous contingencies were planned in detail, some of which had to be implemented. The most significant contingency operation was a high-pressure coiled-tubing milling operation to clean out 2,500 ft of formation and perforating debris that plugged the tubing string.
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