The high-profile blowout at Macondo well in the US Gulf of Mexico, brought the challenges and the risks of drilling into high-pressure, high-temperature (HPHT) fields increasingly into focus. Technology, HSE, new standards, such as new API procedures, and educating the crew seem to be vital in developing HPHT resources. High-pressure high-temperature fields broadly exist in Gulf of Mexico, North Sea, South East Asia, Africa, China and Middle East. Almost a quarter of HPHT operations worldwide is expected to happen in American continent and the majority of that solely in North America. Oil major companies have identified key challenges in HPHT development and production, and service providers have offered insights regarding current or planned technologies to meet these challenges. Drilling into some shale plays such as Haynesville or deep formations and producing oil and gas at HPHT condition, have been crucially challenging. Therefore, companies are compelled to meet or exceed a vast array of environmental, health and safety standards.
This paper, as a simplified summary of the current status of HPHT global market, clarifies the existing technological gaps in the field of HPHT drilling, cementing and completion. It also contains the necessary knowledge that every engineer or geoscientist might need to know about high pressure high temperature wells. This study, not only reviews the reports from the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) and important case studies of HPHT operations around the globe but also compiles the technical solutions to better maneuver in the HPHT market. Finally, the HPHT related priorities of National Energy Technology Laboratories (NETL), operated by the US Department of Energy (DOE), and DeepStar, as a strong mix of large and mid-size operators are investigated.
This paper presents a methodology for connecting geology, hydraulic fracturing, economics, environment and the global natural gas endowment in conventional, tight, shale and coalbed methane (CBM) reservoirs. The volumetric estimates are generated by a variable shape distribution model (VSD). The VSD has been shown in the past to be useful for the evaluation of conventional and tight gas reservoirs. However, this is the first paper in which the method is used to also include shale gas and CBM formations.. Results indicate a total gas endowment of 70000 tcf, split between 15000 tcf in conventional reservoirs, 15000 tcf in tight gas, 30000 tcf in shale gas and 10000 tcf in CBM reservoirs. Thus, natural gas formations have potential to provide a significant contribution to global energy demand estimated at approximately 790 quads by 2035.
A common thread between unconventional formations is that nearly all of them must be hydraulically fractured to attain commercial production. A significant volume of data indicates that the probabilities of hydraulic fracturing (fracking) fluids and/or methane contaminating ground water through the hydraulically-created fractures are very low. Since fracking has also raised questions about the economic viability of producing unconventional gas in some parts of the world, supply cost curves are estimated in this paper for the global gas portfolio. The curves show that, in some cases, the costs of producing gas from unconventional reservoirs are comparable to those of conventional gas.
The conclusion is that there is enough natural gas to supply the energy market for nearly 400 years at current rates of consumption and 110 years with a growth rate in production of 2% per year. With appropriate regulation, this may be done safely, commercially, and in a manner that is more benign to the environment as compared with other fossil fuels.
Neber, Alexander (Schlumberger) | Cox, Stephanie (Schlumberger) | Levy, Tom (Schlumberger) | Schenk, Oliver (Schlumberger) | Tessen, Nicky (Schlumberger) | Wygrala, Bjorn (Schlumberger) | Bryant, Ian David (Schlumberger)
New tools are now available to provide a rigorous and systematic play-based exploration approach to the evaluation of unconventional resources. Coupled with petroleum system modeling, this methodology offers an efficient and effective approach to identify "sweet spots?? early in the life of resource plays. Petroleum system modeling can be applied to predict the type and quantity of hydrocarbon in shale formations, as well as the proportion of adsorbed gas and geomechanical properties that are important for hydraulic fracture stimulation of shale reservoirs. Maps of these properties are then converted to chance-of-success maps for hydrocarbon generation, retention, and pore volume that can be integrated with nongeological factors, such as access and drilling depth required to reach target reservoirs. These play-based maps are expressed in probability units, so simple map multiplication provides a map of the play's overall chance of success, delineating the sweet spots. A similar methodology is applicable to evaluation of coalbed methane resources.
In this paper, we illustrate this methodology using examples from shale oil and gas shale plays in North America. These include data-rich plays from the North Slope of Alaska and data-poor plays from the northeastern and southern regions of the United States, which are more representative of many Asia-Pacific basins. We show how predictions from petroleum system modeling based on sparse data provide a good match with results of subsequent development drilling and production.
Petroleum system-based assessment of resources in place, combined with an assessment of overall play risk, enables companies to make decisions on acquisition of acreage early in the life of unconventional resource plays based on the probability of them containing economically viable resources.