Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract 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.
- North America > United States > Texas (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.68)
- Geology > Mineral (0.46)
- Geology > Rock Type (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.34)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Mississippi > Thomasville Field (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- (53 more...)
Summary Most estimates of the resource endowment [original gas in place (OGIP)] reported for world unconventional gas start with Rogner's top-down study (Rogner 1997). That global estimate is most likely quite conservative because the oil and gas industry has discovered enormous volumes of shale gas around the world since the 1990s. The data from these new reservoirs add substantially to our understanding of the unconventional resource base. Furthermore, the uncertainty of Rogner's assessment was not quantified. Thus, considering the uncertainty, a new assessment of original unconventional gas in place worldwide is needed. The objective of this project was to estimate the probabilistic distributions of original volumes of gas trapped in coalbed, tight-sand, and shale reservoirs worldwide. To accomplish this objective, we reviewed published assessments of coal and conventional and unconventional resources and established the quantitative relationship between unconventional gas [coalbed methane (CBM), tight-sands gas, and shale gas] and the conventional hydrocarbon (coal, conventional gas, and oil) resource endowments for North America. Then, we used this relationship to extrapolate original unconventional gas in place worldwide. Our assessment of the world resource endowment established an unconventional OGIP of 83,400 Tcf (P10) to 184,200 Tcf (P90), which is 2.6 to 5.7 times greater than Rogner's estimate of 32,600 Tcf. Our regional assessments of unconventional OGIP should help industry better target its efforts to rapidly accelerate the development of unconventional gas resources worldwide. The methodology used to assess the distribution of each type of unconventional OGIP may be used to estimate unconventional gas resources at the country or basin level, given knowledge of the coal in place and technically recoverable resources of conventional hydrocarbons.
- North America > United States > Wyoming (1.00)
- North America > United States > Texas (1.00)
- North America > United States > Colorado (1.00)
- (5 more...)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.66)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Wind River Basin (0.99)
- North America > United States > Wyoming > Uinta Basin (0.99)
- (90 more...)
Abstract Post-production performance after hydraulic fracturing has been studied for decades. Most of the issues that arise are related to drainage area and low pore pressure after the fracture is created. The goal of hydraulic fracturing is to always try to maintain the original reservoir pressure while still providing the best geometry possible. Treatment options vary, depending on the pressure and capacity of the formation to return fluids pumped to minimize face damage. Some tight-gas wells respond very well to new, improved fracturing techniques, and proppant-carrying fluids have been continuously modified to reduce damage in the formation. But, for some wells, such as the gas fields in the Burgos basin in North Mexicoโlocated in the North-East area of the country and bordered with South Texas in the USAโproblems still persist. This is especially problematic in unconventional gas reservoirs, such as ultralow-permeability or tight-gas sands. When fracturing, the damage mechanism must be mitigated to help prevent fracture face damage. By reducing fracture face damage caused by the use of conventional surfactants, which absorb rapidly within the first few inches and result in fluid phase trapping, relative permeability, and wettability issues, substantially increased regained permeability can be achieved in unconventional reservoirs, with the primary purpose using surfactant-reducing surface and capillary tension. This study discusses revised operations where a novel microemulsion (ME) surfactant was used, the fluid recovery that occurred during the cleanout process, and the hydrocarbons production a few months after the stimulation. Also, these wells were compared, as much as possible, to those that received a conventional treatment. Results demonstrate exceptional water recoveries compared with conventional ME surfactant treatments.
- North America > United States > Texas (1.00)
- North America > Mexico (1.00)
- North America > United States > Wyoming > Sweetwater County (0.41)
- North America > United States > Texas > Vicksburg Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Queen City Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (31 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Canadian Unconventional Resources Conference held in Calgary, Alberta, Canada, 30 October-1 November 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract A proliferation of massive new resource rock (shale) gas fields has come on-stream in the past several years. This has significantly increased gas production and, along with an economic slowdown globally, these factors have combined to create a gas glut in North America and a corresponding fall of gas prices. The industry response to these very low prices has been to reduce the number of rigs drilling for gas; many have been redeployed to several promising new (or reinvented) liquids producing "shale" fields, including gas shales making condensate, as well as traditional very low permeability oil formations. The development of a new completion approach quickly transformed the low-permeability sector of gas and oil well completions--drill a long (flat and straight) lateral section through the heart of the reservoir and then complete with transverse hydraulic fracture stimulations at several points along the lateral, just as if each point (perforation set) were an independent vertical well location (i.e., the Shale Completion Model). The industry also adopted as its primary horizontal completion technique a process called "perf-and-plug," in which pumpdown plugs are used with attached multifire perforating guns. At least three and often up to seven separate intervals are perforated and simultaneously fracture stimulated, adding potential challenges to effectively place proppant into all fractures and achieve or maintain near-wellbore (NWB) conductivity. Today's drilling is now focusing on liquids plays, which make effective fracture conductivity far more important. The ways in which more conductivity can be delivered need to be revisited, be it with additives, proppant selection, or design approach. This paper reviews fracturing state-of-the-art methods for ultralow-permeability liquids-producing reservoirs and shows how fracture conductivity and economic optimization can be better achieved.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.24)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.97)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.68)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (44 more...)
Abstract Although CO2 EOR is a well-accepted technology with 30+ years' field history, the optimization in its design and operation is historically constrained by the oil price โ trying to minimize the cost especially when oil price is low. When we enter a high oil price regime, CO2 becomes a valuable commodity and its supply starts to limit the flood operation and design. This paper will first review the industrial practice of CO2 design and optimization and the current status of CO2 projects within Chevron. We then focus on a case study to demonstrate the impact of reservoir heterogeneity on flood design. The field was originally designed as crestal gravity stable CO2 injection based on the excellent water flood performance. Good initial oil response was observed but followed by high gas recycling and complicated operational issues. The simulation study suggests that the existence of high permeability, vertical conduits causes the CO2 flow rates in the reservoir significantly higher than the critical gravity-stable flow rate resulting in high gas recycling. Therefore balancing recovery efficiency and project economics is a challenge for gravity stable injection design. A tapered WAG design is proposed to improve operational flexibility and recovery efficiency in this mature field. The case study also demonstrates that it is critical to include proper characterization of flow barriers and channels for a successful CO2 flood design.
- North America > United States > Wyoming > Southwest Wind River Basin > Beaver Creek Field > Wind River Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (28 more...)
Abstract This paper involves the use of simulation models and the decline curve analysis (DCA) as a production optimization and forecasting tools. Production data from three neighboring counties (with high, medium and low cumulative gas productions) of the Eagle Ford shale, an analogue to the Shublik shale of Alaska, was analyzed using the DCA to correlate production performance with completion (horizontal leg/stages of fracture) and length of horizontal leg. We built and run generic simulation models using realistic range of properties. Simulation results provided a better understanding of interplay between static properties and dynamic behavior. The simulation results highlight how and when the key influential elements such as gas desorption, fracture closure with depletion, varying medium and fracture properties, different hydraulic fracture configuration, and various natural fracture networks will affect the well production.
The use of the method proposed in this paper would result in better and more reliable production forecast at the Eagle Ford and other young producing shale reservoirs possessing short production history. The modeling of these complex reservoir geometry and fracture networks would give an extensive understanding of the flow mechanics in shale reservoirs and identify the key parameters affecting production performance. It would also serve as a screening tool for fracturing/re-fracturing operations and give optimal hydraulic fracture configuration for various mediums and natural fracture networks.
Results from the decline curve analysis of 24 producing wells with production histories of 9-57 months showed an increase in reserves with more fracture stages but not at all instances which makes the use of simulation models very valuable and necessary in obtaining further results and explanations. DCA generated different forecast depending on which part of data were used. This clearly indicated the need for running simulations. Simulation runs can generate more reliable production forecast of which the decline part can be used to evaluate the capability of DCA to reproduce the production profiles. The results from simulation can provide a clear picture of the role of key influencing parameters from both reservoir and well stimulation/completion on well production performance.
The results from this study will provide answer to the following questions: How long the production history needs to be for DCA to generate reliable forecasts?
What are the key reservoir and completion elements that strongly affect the production? And what parameters control the choice of well spacing?
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Sugarkane Field > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Sugarkane Field > Austin Chalk Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (18 more...)
Abstract An unconventional reservoir poses not only difficulties in producing it economically but also requires constrains about the well construction and tubular selection in order to keep the budget in acceptable limits. The tubular used for well construction and well completion must offer maximum integrity at, if possible, minimum costs for the life of the well. The costs associated with tubular are generated by the steel price plus the connection costs. Use of premium connections may not be justified in all unconventional reservoir applications, but as this study will prove, they offer better solutions when the life if the well is considered. This paper starts with a review of main tight gas fields worldwide and based on the well analysis a general tendency for well completion will be shown. The second part of the work will focus in analyzing casing design criteria used in afore mentioned fields. As a result a comprehensive discussion about casing and coupling selection for unconventional wells will be generated. Premium versus non premium connections will be discussed and their impact on the life of the well will be analyzed.
- North America > United States > Colorado (1.00)
- North America > United States > Texas > Panola County (0.29)
- Africa > Middle East > Algeria > Illizi Province (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.40)
- North America > United States > Wyoming > Great Basin (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin (0.99)
- North America > United States > Utah > Uintah Basin > Wasatch Formation (0.99)
- (54 more...)