|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
The Prudhoe Bay field, located on the North Slope of Alaska, is the largest oil and gas field in North America. The main Permo-Triassic reservoir is a thick deltaic high-quality sandstone deposit about 500 ft thick with porosities of 15 to 30% BV and permeabilities ranging from 50 to 3,000 md. The field contains 20 109 bbl of oil overlain by a 35 Tcf gas cap. The oil averages 27.6 API gravity and has an original solution gas-oil ratio (GOR) of about 735 scf/STB. Under much of the oil column area, there is a 20- to 60-ft-thick tar mat located above the oil-water contact (OWC).
A new extended-release (ER) scale-inhibitor technology showing significantly increased lifetimes has been applied in the Permian Basin. Tomson Technologies and Group 2 Technologies, in partnership with Occidental Petroleum (Oxy), implemented a scale-squeeze program for this carrier system. It allows for fewer squeeze treatments, which results in lower chemical usage, decreased plugging risk, and reduced environmental impact. Squeeze programs are an effective field treatment strategy to prevent scale formation in wells for extended periods of time. However, in some cases, squeeze lifetimes can be short, leading to frequent re-squeezing and production decreases, lowering overall economic recoveries.
The study outlined in the complete paper focuses on developing models of the Upper Cretaceous Waha carbonate and Bahi sandstone reservoirs and the Cambrian-Ordovician Gargaf sandstone reservoir in the Meghil field, Sirte Basin, Libya. The objective of this study is to develop a representative geostatistically based 3D model that preserves geological elements and eliminates uncertainty of reservoir properties and volumetric estimates. This study demonstrates the potential for significant additional hydrocarbon production from the Meghil field and the effect of heterogeneity on well placement and spacing. The reservoir of interest consists of three stratigraphic layers of different ages: the Waha and Bahi Formations and the Gargaf Group intersecting the Meghil field. The Waha reservoir is a porous limestone that forms a single reservoir with underlying Upper Cretaceous Bahi sandstone and Cambro-Ordovician Gargaf Group quartzitic sandstone.
When the CEO of Occidental Petroleum described the company's future this week, it was clear the company will not be moving away from hydrocarbons. By 2050, Occidental expects to still be a big oil company, but producing oil and natural gas is not likely to be its biggest source of revenue. Several decades from now, Vicki Hollub, the president and chief executive officer of Occidental, predicted that income from carbon capture and storage "will be bigger than oil production revenue." During the plenary session for the Unconventional Resources Technology Conference (URTeC) she described how Occidental is scaling up its carbon-capture business, beginning with a facility in the Permian Basin with the capacity to capture 1 million tons of CO2 per year. First announced by Occidental in early 2019, design is in progress with construction expected in 2023. The planned capacity is 250 times greater than any such plant in existence and will be an early test of the economics of large-scale carbon capture.
Occidental Petroleum (Oxy) said this week it has agreed to sell almost 25,000 net acres in the Permian Basin of Texas to Colgate Energy Partners III for nearly $508 million. Average output of the properties amounts to 10,000 BOE/D from about 360 wells in the southern Delaware Basin, Houston-based Oxy reported in its announcement. The sale, expected to close in the third quarter, will boost Midland-based Colgate's holdings in the Permian to about 83,000 acres with an estimated production of 55,000. Colgate said it plans to run up to six drilling rigs by year's end and boost average production to 75,000 BOE/D by 2022. Proceeds from the sale will be used to pay down Oxy's debt that was around $35.4 billion in March, down slightly from the $36.03-billion debt reported last June.
As industry buzzwords go, "automation" has spent its time in oilfield vernacular climbing the ranks of widely used terms. It now resides as one of the go-to designations for signs of advancement in any number of disciplines. Its use has been tied most frequently with drilling operations as contractors look to keep employees out of harm's way via a robotic takeover of most motion-intensive jobs on the rig's drill floor--basically anything that grips, clamps, or spins. More recently, the term has moved away from the drill floor and into other well construction operations allowing for things such as remote, real-time measurements without the need for boots on the ground. For areas like west Texas and the Permian Basin shales, having the option for remote readouts and a component of automation that can allow for corrective actions should the need arise can go a long way in terms of safety and efficiency gains as well as better manpower application.
Gao, Xiang (Southwest Oil and Gas Field Company of CNPC) | Zeng, Jiaxin (Sichuan Changning Natural Gas Development Co., Ltd) | Xie, Jiajun (Sichuan Changning Natural Gas Development Co., Ltd) | Tang, Liang (Sichuan Changning Natural Gas Development Co., Ltd) | Li, Wenzhe (Sichuan Changning Natural Gas Development Co., Ltd) | Gui, Feng (Baker Hughes) | Ghosh, Amitava (Baker Hughes) | Ong, See Hong (Baker Hughes) | Huang, Xingning (Baker Hughes) | Deng, Lichuan (Baker Hughes)
Abstract Horizontal well drilling contribute to a dramatic increase of shale gas production in unconventional reservoirs. However, the drilling is also risky and challenging with different types of drilling problems often encountered including stuck pipes, inflows, losses and pack-offs, etc. To reduce shale-gas development costs, shale gas operators are faced with finding effective solutions to minimize drilling risks and improve drilling efficiency. A holistic workflow, which can be divided into three steps: pre-drilled modelling and assessment, real-time monitoring, and post-drilled validation, is proposed. Based on the pre-drilled geomechanical modeling, mud weights, mud formulations and casing setting depths are optimized to ensure wellbore stability during the drilling process. Real-time operations involve monitoring drilling parameters and cavings characteristics (shape and volume), and providing updated recommendations for field drilling engineers to mitigate and reduce borehole instability related problems. During the post-drilled stage, the updated geomechanical model will be used for optimizing the drilling designs of upcoming wells. With geomechanics as foundation, a systematic workflow was developed to provide integrated solutions by using multiple technologies and services to reduce serious wellbore instability caused by abnormal formation pressures, wellbore collapse and other complex drilling problems. The implementation of the systematic and holistic workflow has proven to be extremely successful in supporting the drilling of shale gas wells in China. The integrated approach, which was applied in a Changning shale gas block in Sichuan Basin for the first time in March 2019, recorded an improvement in ROP by 111.2% and a reduction in mud losses by 89.9% compared with an offset well without the risk mitigation strategy applied in the same pad. The geomechanics-based approach provides a convenient and effective means to assist field engineers in mud weight optimization, drilling risk assessments, and horizontal well drilling performance evaluation. The approach can also be extended to reduce potential drilling risks and improve wellbore stability, all of which contributes to reducing drilling costs and optimizing subsequent massive hydraulic fracturing jobs.
US shale producers Cabot Oil & Gas and Cimarex Energy are the latest to declare a "merger of equals" in a deal valued at around $17 billion, based on recent equity prices. Announced today, the terms of the deal will result in Cimarex shareholders owning about 50.5% of the combined company and Cabot shareholders owning approximately 49.5%. The deal brings together Houston-based Cabot's gas-rich portfolio, comprising almost 173,000 acres in the Marcellus Shale, with Cimarex's oil-dominated 560,000 net acres in the Permian Basin and Anadarko Basin. On a pro forma basis, the merged company will produce around 600,000 BOE/D from the three basins. The companies expect $100 million in savings to materialize within 2 years of the deal closing and to generate around $4.7 billion in free cash flow from 2022 to 2024.
James Blaney is an engineer on a hydraulic fracturing fleet for Liberty Oilfield Services, and is based in the Permian Basin. He holds a bachelor's degree in petroleum engineering from the Colorado School of Mines (CSM). While at CSM, he was an active member of the CSM SPE Student Chapter. He volunteered regularly at fundraising events and was a member and captain of the CSM PetroBowl team.
Abstract Growth in the coal seam gas industry in Queensland, Australia, has been rapid over the past fifteen years, with greater than USD 70 billion invested in three liquified natural gas export projects supplied by produced coal seam gas. Annual production is of the order of 40 Bscm or 1,500 PJ, with approximately 80% of this coming from the Jurassic Walloon Coal Measures of the Surat Basin and 20% from Permian coal measures of the Bowen Basin. The Walloon Coal Measures are characterized by multiple thin coal seams making up approximately 10% of the total thickness of the unit. A typical well intersects 10 to 20 m of net coal over a 200 to 300 m interval, interbedded with lithic-rich sandstones, siltstones, and carbonaceous mudstones. The presence of such a significant section of lithic interburden within the primary production section has led to a somewhat unusual completion strategy. To maximize connection to the gas-bearing coals, uncemented slotted liners are used; however, this leaves fluid-sensitive interburden exposed to drilling, completion, and produced formation fluids over the life of a well. External swellable packers and blank joints are therefore used to isolate larger intervals of interburden and hence minimize fines production. Despite these efforts, significant fines production still occurs, which leads to failure of artificial lift systems and the need for expensive workovers or lost wells. Fines production has major economic implications, with anecdotal reports suggesting up to 40% of progressive cavity pump artificial lift systems in Walloon Coal Measures producers may be down at any one time. The first step in solving this problem is to identify the extent and distribution of fines production. The wellbore completion strategy above, however, precludes use of mechanical calipers to identify fines production-related wellbore enlargement. A new caliper-behind-liner technique has therefore been developed using a multiple-detector density tool. Data from the shorter spacing detectors is used to characterize the properties of the liner as well as the density of the annular material. This is particularly important to evaluate as the annulus fill varies between gas, formation water, drilling and completion fluids, and accumulated fines. The longer spacing detector measurements are then used in conjunction with pre-existing open-hole formation density measurement to determine the thickness of the annulus, and hence hole size, compensating for liner and annulus properties. This methodology has been applied to several wells completed in the Walloon Coal Measures. Results have demonstrated the ability to identify zones of borehole enlargement behind slotted liner, as well as intervals of either gas or fines accumulation in the annulus. In addition, the technique has been successful in verifying the placement of swellable packers and their integrity. The application of this solution has been used to drive improvements in the design of in-wellbore completion programs and in the future will help drive recompletion decisions and trigger proactive workovers.