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On April 20, 2010, BP’s Deepwater Horizon oil rig exploded in the Gulf of Mexico. This turned out to be one of the worst environmental disasters in recent history. This high-profile blowout at the Macondo well in the Gulf of Mexico, brought the challenges and the risks of drilling into high-pressure, high-temperature (HPHT) fields increasingly into focus. New Technology, HSE regulations, new standards, such as newly recommended procedures by the American Petroleum Institute (API), and extensive training programs for the drilling crew seem to be vital in developing HPHT resources. High-pressure high-temperature fields exist in Gulf of Mexico, North Sea, Southeast Asia, Africa and the Middle East. Almost a quarter of HPHT operations worldwide are expected to happen in the American continent particularly in North America. Major oil companies have tried to identify key challenges in HPHT development and production, and several service companies have offered many insights regarding current or planned technologies to meet these challenges. However, there are so many factors that need to be addressed and learned in order to safely overcome the challenges of drilling into and producing from HPHT oil and gas wells.
Drilling into HPHT wells is a new frontier for the oil and gas industry. The growing demand for oil and gas throughout the world is driving the exploration and production industry to look for new resources. Some of these resources are located in deeper formations. According to US Minerals Management Service (MMS), over 50% of proven oil and gas reserves in the US lie below 14,000 ft. subsea. As we drill into deeper formations we will experience higher pressures and temperatures.
Drilling operations in such high pressure and high temperature environments can be very challenging. Therefore, companies are compelled to meet or exceed a vast array of technical limitations as well as environmental, health and safety standards. This paper explains the technological challenges in developing HPHT fields, deepwater drilling, completions and production considering the reports from the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), formerly known as the Minerals Management Service (MMS). It reviews the HPHT related priorities of National Energy Technology Laboratory (NETL), operated by the US Department of Energy (DOE), and DeepStar Committees for Technology Development for Deepwater Research.
Key words: High pressure high temperature wells environment; Oil and gas industry; Gulf of Mexico Shadravan, A., & Amani, M. (2012). HPHT 101-What Petroleum Engineers and Geoscientists Should Know About High Pressure High Temperature Wells Environment. Energy Science and Technology, 4(2),-0. Available from: URL: http://www.cscanada.net/index.php/est/article/view/10.3968/j.est.1923847920120402.635
DOI: http://dx.doi.org/10.3968/j.est.1923847920120402.635
INTRODUCTION
Projections of continued growth in hydrocarbon demand are driving the oil and gas industry to explore new or under-explored areas. As the search for petroleum becomes more extreme in terms of depths, pressures, and temperatures, companies are leading the way with innovative technologies and products for HPHT drilling. A number of innovations are in the pipeline to help companies access hydrocarbon that were once deemed too difficult to exploit. In a case of huge investments for new oil and natural gas discoveries, the oil industry has reached an agreement: no easy fields to be developed remain undiscovered, especially in offshore environments. According to Simmons, development of new approaches to drilling deep HPHT wells is required to meet engineering requirements while keeping projects economically feasible. Challenges on well drilling such as drilled extensions over 20,000ft, sub-salt drilling, very narrow drilling windows, operational challenges like lost of circulation, stuck pipe, and well control issues are even more probable when drilling in HPHT environments. The most common HPHT definition is when the pressure exceeds 10,000 psi (690 bar) and the temperature exceeds 300 °F ( 149 °C ).
According to some studies in the near future, HPHT would be defined when the pressure if over 15,000 psi and the temperature more than 300 °F. To help identify HPHT operating environments, safe operating envelopes and technology gaps, new classifications have been developed. These classifications segment HPHT operations into main three tiers. Tier I refers to the wells with initial reservoir pressures between 10,000 psi to 20,000 psi and/or reservoir temperatures between 300 °F to 400 °F. To date, most of the HPHT operations in shale plays (GuoJiRajabovFriedheimPortella et al., 2012; GuoJiRajabovFriedheim & Wu, 2012; Joshi, 2012; Joshi & Lee, 2013; Rajabov et al., 2012) and many of the upcoming HPHT deepwater gas/ oil wells, particularly in the Gulf of Mexico, fall into Tier I . Kristin field is a well-known HPHT field in Norway with the reservoir pressure of 13200 psi and the temperature of about 350 °F. Tier II is called “Ultra” HPHT and includes any reservoir with pressures more than 20,000 and less than 30,000 psi and/or temperatures between 400 °F to 500 °F. Several deep gas reservoirs on the US land and the Gulf of Mexico continental shelf fall into this category (Payne et al., 2007). Tier III encompasses “extreme” HPHT wells, with reservoir pressures from 30,000 psi to 40,000 psi and/ or temperatures between 500 °F to 600 °F. Tier III is the HPHT segment with the most significant technology gaps. In the past HPHT (or HTHP) was attributed to any condition with pressure or temperature above the atmospheric condition. Service companies, operators, cement/drilling fluid testing equipment companies and other pipe or tools manufacturers, each, came up with a slightly different definition for HPHT condition. Most companies currently categorize their operations, products or tools into the three main tiers shown in Figure 1, however, with different pressure and temperature boundaries for each tier, Figures 2, 3, 4, 5, 6 and 7. This can be due to the fact that, for instance, a mud engineer worries more about the pressure and the temperature at which the drilling fluid might fail while a cementing engineer prioritizes when and how fast the cement sets at HPHT condition. These turning points (pressures and temperatures) are almost close but not the same. Also regulations in various geographical locations might affect this definition, for example in Norway ? or ? is used instead of ? and ? in defining a HPHT project; in other words, if either temperature or pressure meets the HPHT condition (10,000 psi or 300 °F), the project counts as a HPHT. In the UK, HPHT is formally defined as a well having an undisturbed bottom hole temperature of greater than 300 °F (149 °C) and a pore pressure of at least 0.8 psi/ft (?15.3 lbm/gal) or requiring a BOP with a rating in excess of 10,000 psi [68.95 MPa]. Although the term was coined relatively recently wells meeting the definition drilled and completed around the world for decades (Schlumberger, 2012). In North Sea some projects are still considered HPHT with the temperatures over 250 °F.
Drilling into HPHT wells is a new frontier for the oil and gas industry. The growing demand for oil and gas throughout the world is driving the exploration and production industry to look for new resources. Some of these resources are located in deeper formations. According to US Minerals Management Service (MMS), over 50% of proven oil and gas reserves in the US lie below 14,000 ft. subsea. As we drill into deeper formations we will experience higher pressures and temperatures.
Drilling operations in such high pressure and high temperature environments can be very challenging. Therefore, companies are compelled to meet or exceed a vast array of technical limitations as well as environmental, health and safety standards. This paper explains the technological challenges in developing HPHT fields, deepwater drilling, completions and production considering the reports from the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), formerly known as the Minerals Management Service (MMS). It reviews the HPHT related priorities of National Energy Technology Laboratory (NETL), operated by the US Department of Energy (DOE), and DeepStar Committees for Technology Development for Deepwater Research.
Key words: High pressure high temperature wells environment; Oil and gas industry; Gulf of Mexico Shadravan, A., & Amani, M. (2012). HPHT 101-What Petroleum Engineers and Geoscientists Should Know About High Pressure High Temperature Wells Environment. Energy Science and Technology, 4(2),
DOI: http://dx.doi.org/10.3968/j.est.1923847920120402.635
INTRODUCTION
Projections of continued growth in hydrocarbon demand are driving the oil and gas industry to explore new or under-explored areas. As the search for petroleum becomes more extreme in terms of depths, pressures, and temperatures, companies are leading the way with innovative technologies and products for HPHT drilling. A number of innovations are in the pipeline to help companies access hydrocarbon that were once deemed too difficult to exploit. In a case of huge investments for new oil and natural gas discoveries, the oil industry has reached an agreement: no easy fields to be developed remain undiscovered, especially in offshore environments. According to Simmons, development of new approaches to drilling deep HPHT wells is required to meet engineering requirements while keeping projects economically feasible. Challenges on well drilling such as drilled extensions over 20,000ft, sub-salt drilling, very narrow drilling windows, operational challenges like lost of circulation, stuck pipe, and well control issues are even more probable when drilling in HPHT environments. The most common HPHT definition is when the pressure exceeds 10,000 psi (690 bar) and the temperature exceeds 300 °F ( 149 °C ).
According to some studies in the near future, HPHT would be defined when the pressure if over 15,000 psi and the temperature more than 300 °F. To help identify HPHT operating environments, safe operating envelopes and technology gaps, new classifications have been developed. These classifications segment HPHT operations into main three tiers. Tier I refers to the wells with initial reservoir pressures between 10,000 psi to 20,000 psi and/or reservoir temperatures between 300 °F to 400 °F. To date, most of the HPHT operations in shale plays (GuoJiRajabovFriedheimPortella et al., 2012; GuoJiRajabovFriedheim & Wu, 2012; Joshi, 2012; Joshi & Lee, 2013; Rajabov et al., 2012) and many of the upcoming HPHT deepwater gas/ oil wells, particularly in the Gulf of Mexico, fall into Tier I . Kristin field is a well-known HPHT field in Norway with the reservoir pressure of 13200 psi and the temperature of about 350 °F. Tier II is called “Ultra” HPHT and includes any reservoir with pressures more than 20,000 and less than 30,000 psi and/or temperatures between 400 °F to 500 °F. Several deep gas reservoirs on the US land and the Gulf of Mexico continental shelf fall into this category (Payne et al., 2007). Tier III encompasses “extreme” HPHT wells, with reservoir pressures from 30,000 psi to 40,000 psi and/ or temperatures between 500 °F to 600 °F. Tier III is the HPHT segment with the most significant technology gaps. In the past HPHT (or HTHP) was attributed to any condition with pressure or temperature above the atmospheric condition. Service companies, operators, cement/drilling fluid testing equipment companies and other pipe or tools manufacturers, each, came up with a slightly different definition for HPHT condition. Most companies currently categorize their operations, products or tools into the three main tiers shown in Figure 1, however, with different pressure and temperature boundaries for each tier, Figures 2, 3, 4, 5, 6 and 7. This can be due to the fact that, for instance, a mud engineer worries more about the pressure and the temperature at which the drilling fluid might fail while a cementing engineer prioritizes when and how fast the cement sets at HPHT condition. These turning points (pressures and temperatures) are almost close but not the same. Also regulations in various geographical locations might affect this definition, for example in Norway ? or ? is used instead of ? and ? in defining a HPHT project; in other words, if either temperature or pressure meets the HPHT condition (10,000 psi or 300 °F), the project counts as a HPHT. In the UK, HPHT is formally defined as a well having an undisturbed bottom hole temperature of greater than 300 °F (149 °C) and a pore pressure of at least 0.8 psi/ft (?15.3 lbm/gal) or requiring a BOP with a rating in excess of 10,000 psi [68.95 MPa]. Although the term was coined relatively recently wells meeting the definition drilled and completed around the world for decades (Schlumberger, 2012). In North Sea some projects are still considered HPHT with the temperatures over 250 °F.