|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Its reward for years of struggling to adapt to low prices and weak demand for its oil and gas has been an epic crash. Canadians selling change say it is time to consider possibilities that seemed inconceivable in the past. So many unprecedented changes have occurred in the Canadian oil business that it is impossible to compare the current downturn to anything seen before. Steam-assisted gravity drainage (SAGD) performance in bitumen-recovery projects in Alberta is affected by geological deposits, reservoir quality, and operational experience. Although polymer flooding has become a promising enhanced oil recovery (EOR) technique, no field tests have been performed to date in Alaska’s underdeveloped heavy-oil reservoirs.
Wellbore instability has been experienced in areas of the Marcellus Shale and can become particularly troublesome in the superlaterals that are becoming more prevalent in that play. Often the instability while drilling these very long lateral wells is minimal; problems are more likely to occur while tripping out after reaching TD. The most common instability events when pulling out of the hole appear to be tight hole, pack-off and stuck pipe. These problems often worsen with time, indicating there is some time-dependence to the failure mechanism.
In order to develop effective mitigation strategies to combat the instability, it is imperative that the failure mechanism be correctly identified. Previous publications (Kowan and Ong, 2016; Addis et al. 2016; Riley et al. 2012) have suggested that bedding planes may play a role in some of the drilling problems experienced in the Marcellus Shale. In this paper, we will present a case study from the Marcellus that shows conclusive proof of weak bedding plane failure along a lateral well, where thousands of feet of anisotropic failure were captured with a LWD image log.
This image provided confirmation of the presence and failure of weak bedding planes in the Marcellus Shale. The image was also used to validate an existing geomechanical model for the area and gave the operator more confidence in the mitigation strategies developed from that geomechanical model, which had been based on the assumption that weak bedding was contributing to difficulty experienced on multiple lateral wells when tripping out of the hole.
This case study will begin with an overview of the geomechanical model, including the drilling history, stress/pore pressure model and rock properties. Next, some highlights from the image log, showing anisotropic bedding plane failure, will be featured as well as a comparison of the image to the geomechanical model. This case study will conclude with a review of proposed mitigation strategies that could be implemented by the operator to limit the risks posed by weak beds and minimize instability, when drilling laterals in this area, or similarly complex areas, of the Marcellus Shale.
The latest focus on floating offshore developments is to minimize or remove the human presence onboard by utilizing remote operations. This may reduce personnel exposure and potentially overall costs by using new technologies. Existing codes or regulations are not tailored to address unmanned (UM) or minimally manned (MM) floating installations. Such floating facilities are remotely operated from a nearby facility or a control center located onshore. Offshore facilities remotely operated require real time monitoring, control automation, and maintenance procedures incorporating remote diagnostics and simulations, with minimal human intervention. This concept brings into focus the design of the remote-control center, the communication infrastructure, smart functionalities, digital twins and simulation technologies. In order to achieve the objectives of an UM or MM facility, hull and machinery inspections onboard the facility are expected to be minimized, and design features adopted for remote inspection using new technologies. Enhancing the fatigue life of the hull structure and reliability of critical machinery are fundamental to this concept.
This paper proposes guidance to develop and manage an UM or MM facility through lifecycle activities of design, construction, integration, testing, operation, monitoring, inspection and maintenance in comparison with conventional facilities. The adopted approach identifies risk related to the concept and proposes measures to help develop appropriate design and safety requirements under a lifecycle perspective. The existing codes, standards and class society rules contain applicable requirements for floating facilities related to design, operations and maintenance. The study is based on the review of existing rules and regulations including associated gap analysis. The study concludes that existing structural rules may be applied as a base requirement to address structural integrity, inspection and maintenance risk. From machinery perspective, new technologies will need to be implemented to address monitoring, control, inspection and maintenance issues. The paradigm shift will be in designing the facility to move from a traditional maintenance plan to a Condition-Based Maintenance (CBM) requiring human intervention on a minimal need-basis.
This paper also addresses the design and safety considerations based on risks, new technology qualification (TQ) and human factors for continued operations, since the limited or temporary crew will be required to perform multidisciplinary activities, and habitability design should assist and augment onboard crew ability.
Steam-assisted gravity drainage (SAGD) performance in bitumen-recovery projects in Alberta is affected by geological deposits, reservoir quality, and operational experience. Although polymer flooding has become a promising enhanced oil recovery (EOR) technique, no field tests have been performed to date in Alaska’s underdeveloped heavy-oil reservoirs. Reviewing a myriad of papers presented at different conferences during the past year, I can group the current trends in heavy-oil operations and research into two major categories: Process optimization and use of chemicals as additives to steam and water. The complete paper describes piloting the collection and analysis of distributed temperature and acoustic sensing (DTS and DAS, respectively) data to characterize flow-control-device (FCD) performance and help improve understanding of steam-assisted gravity drainage (SAGD) inflow distribution. Heavy production spiked in two Canadian wells heated by an electric cable, but it is hard to find customers there at a time when Canadian oil prices and customers remember cables in the past that died young.
Heavy production spiked in two Canadian wells heated by an electric cable, but it is hard to find customers there at a time when Canadian oil prices and customers remember cables in the past that died young. In this paper, the authors consider the effect of water chemistry on water/rock interactions during seawater and smart waterflooding of reservoir sandstone cores containing heavy oil. This paper updates a previous case study and presents the results of actual implementation of an optimized steam-injection plan based on the model framework. The complete paper explores technical and economic development options to produce heavy-oil resources at commercial rates and showcases three optimization scenarios of higher recovery efficiency aimed at increasing net present value at the basin level. Field N is a complex heavy-oil field in the north of the Sultanate of Oman.
Shale gas is becoming increasingly important globally. The nature of these reservoirs pose special considerations in reserves estimation. What follows was written in 2001 and needs to be updated based on current experience. Nonetheless, some of the considerations mentioned remain appropriate. As reported in mid-2000, natural gas produced from shale in the US has grown to be approximately 1.6% (0.3 Tcf annually) of total gas production.
Although reserves estimates for known accumulations historically have used deterministic calculation procedures, the 1997 SPE/WPC definitions allow either deterministic or probabilistic procedures. Each of these is discussed briefly in the next two sections. Thereafter--except for another section on probabilistic procedures near the end--the chapter will focus on deterministic procedures because they still are more widely used. Both procedures need the same basic data and equations. Deterministic calculations of oil and/or gas initially in place (O/GIP) and reserves are based on best estimates of the true values of pertinent parameters, although it is recognized that there may be considerable uncertainty in such values.
Summary In a previous work, we introduced a three-parameter scaling solution that models the long-term recovery of dry gas from a hydrofractured horizontal well far from other wells and the boundaries of a shale reservoir with negligible sorption. Here, we extend this theory to account for the contribution of sorbed gas and apply the extended theory to the production histories of 8,942 dry-gas wells in the Marcellus Shale. Our approach is to integrate unstructured big data and physics-based modeling. We consider three adsorption cases that correspond to the minimum, median, and maximum of a set of measured Langmuir isotherms. We obtain data-driven, independent estimates of unstimulated shale permeability, spacing between hydrofractures, well-drainage area, optimal spacing between infill wells, and incremental gas recovery over a typical well life. All these estimates decrease to varying extents with increasing sorption. We find that the average well with median adsorption has a permeability of 250 nd, fracture spacing of 16 m, 30-year drainage length of 79 m, and a 30-year incremental recovery of 67%. Introduction Since 2012, the Marcellus Shale has been by far the most productive US shale play. Producing 25% of the total US dry natural gas, the Marcellus Shale currently produces at least three times more natural gas than any other major US shale play, including, in order of decreasing production, the Permian, Haynesville, Utica, Eagle Ford, Barnett, Woodford, Fayetteville, and Antrim shales (Figure 1). This high productivity has attracted significant attention from developers. The majority of drilling activities have taken place in two sweet spots: northeastern Pennsylvania, which primarily contains dry gas, and southwestern Pennsylvania and northern West Virginia, which produce liquid-rich gas (Popova 2017). Since leading US shale-gas production for the first time in 2012, the Marcellus Shale currently produces three times more than the Permian Basin, the runner-up shale-gas producer. Given how important Marcellus is to the US economy and energy security, it seems worthwhile to comb through the available production data and attempt to extract key information from the wells that are active and productive.
Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. For a long time, the Fruitland formation coals were recognized only as a source of gas for adjacent sandstones. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Coals in the fairway typically have low ash and high vitrinite contents, resulting in large gas storage capacities and excellent permeabilities of 10 md from well-developed cleat systems. Southwest of the fairway, Fruitland coals are typically 20 to 40 ft thick and are considerably underpressured with vertical pressure gradients in some areas of less than 0.20 psi/ft.
McClure, Mark (ResFrac Corporation) | Picone, Matteo (ResFrac Corporation) | Fowler, Garrett (ResFrac Corporation) | Ratcliff, Dave (ResFrac Corporation) | Kang, Charles (ResFrac Corporation) | Medam, Soma (ResFrac Corporation) | Frantz, Joe (ResFrac Corporation)
Hydraulic fracturing and reservoir simulation are used by operators in shale to optimize design parameters such as well spacing, cluster spacing, and injection schedule. In this paper, we address'freqently asked questions' that we encounter when working on hydraulic fracture modeling projects with operators. First, we discuss three high-level topics: (1) data-driven and physics-based models, (2) the modeling workflow, and (3) planar-fracture modeling versus'complex fracture network' modeling. Next, we address specific technical topics related to modeling and the overall physics of hydraulic fracturing: (1) interrelationships between cluster spacing and other design parameters, (2) processes affecting fracture size, (3) fracture symmetry/asymmetry, (4) proppant settling versus trapping, (5) applications of Rate-Transient Analysis (RTA), (6) net pressure matching, (7) Initial Shut-In Pressure (ISIP) trends along the wellbore, and (8) the effect of understressed/underpressured layers. We discuss practical modeling decisions in the context of field observations.