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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.
An exploration well at the Puma West prospect in the deepwater US Gulf has yielded a significant oil discovery for operator BP. The well, on Green Canyon Block 821, was drilled using Seadrill drillship West Auriga to a total depth of 23,530 ft and encountered oil pay in a high-quality Miocene reservoir with fluid properties like productive Miocene reservoirs in the area. Preliminary data supports the potential for a commercial volume of hydrocarbons. The Puma West partners will begin planning an appraisal program to better define the discovered resource. The discovery well has been suspended as a keeper well to preserve future utility.
Bhimpalli, Sarah (ONGC) | Shinde, Ashok (Baker Hughes) | Rao, Bayye L (ONGC) | Perumalla, Satya (Baker Hughes) | Panchakarla, Anjana (Baker Hughes) | Chakrabarti, Prajit (Baker Hughes) | Saha, Sankhajit (Baker Hughes)
Abstract Geomechanics has an important role in assessing formation integrity during well construction and completion. It also has its effect when the wellbore is in production mode. Geomechanical study evaluate the impact of the present day in-situ stress and related mechanical processes on reservoir management. The study field ‘K' belongs to Plio-Pleistocene sequence of deep-water environment with hydrocarbon prospects. This belongs to Post-Rift tectonic stage of evolution with hydrocarbon occurring in structurally controlled traps. As a part of exploration activity, four offset oil wells were drilled earlier which were considered for the geomechanical model construction. Field (K) development plan comprising of six hydrocarbon producers and four water injectors was prepared. Considering the thick water column (300m-650m) in this deep water area of offshore and young unconsolidated sedimentary sequence in the sub-surface, expected pore-pressures can be high whereas the fracture gradient can be low. As a result, the safe drilling mud window can be narrow. Upon successful drilling of a well in such challenging environment without NPT (Non-Productive time), completing the well with best possible technologies suitable to the reservoir's mechanical behavior is utmost important for maximizing the production and minimizing the risk. To mitigate these problems in developing this field, an integrated reservoir geomechanics approach is adopted to optimize the drilling plan and reservoir completion parameters for the planned well. This paper covers the geomechanical study of four wells namely W, X, Y & Z drilled in the field ‘K'. The principal constituents of the geomechanical model are in-situ stresses, pore pressure and the rock mechanical properties. Geomechanical model for the field ‘K' was built utilizing the available data by integrating drilling, geology, petrophysics and reservoir data. Methodology adopted in this paper also highlights how a reliable geomechanical model can be built for a field, which is having data constraints. Constraining of stress magnitudes, orientation and anisotropy added value for efficient well planning in deep waters reservoirs. Calculating well specific reservoir rock mechanical properties, it made possible to identify the most optimal completion strategy. Approach contributed knowledge of geomechanical parameters based on the data of four offset wells has been used for successfully drilling and completion of all the subsequent wells without major challenges. Overall, geomechanical modeling has played a major role in drillability and deliverability of the reservoir. Integrated approach adopted in this paper can be used for well planning and drilling of future wells in East Coast of India with similar geological set up.
Saleh, Khaled (Kuwait Oil Company) | Al-Khudari, Abdulaziz Bader (Kuwait Oil Company) | Al-Najdi, Amer (Kuwait Oil Company) | Al-Azmi, Mejbel Saad (Kuwait Oil Company) | Al-Otaibi, Fahad Barrak (Kuwait Oil Company) | Joshi, Girija Kumar (Kuwait Oil Company) | Abdulkarim, Anar (Halliburton) | Farhi, Nadir (Halliburton) | Nouh, Walid (Halliburton) | Clarion, Benjamin (Halliburton)
Abstract Traditionally, 12.25-in. hole sections in the Jurassic formations were planned to be drilled with mud weight (MW) of 20 ppg and solids content of 45%. The planned drilling would use a rotary assembly from the Hith formation, crossing several zones in which mud losses or gains were likely. The casing would then be set in the thin shale base of the Gotnia formation. A minor inaccuracy in casing setting depth could often lead to well-control issues. Pore pressure drops severely below the shale base and requires a MW of 15 ppg. Passing this shale base can lead to severe losses and potential abandonment of the well. An anhydrite marker is located approximately 50 ft above the shale base. To reduce risk, the operator would normally drill to this marker at a rate of penetration (ROP) of 20-30 ft/hr, then decrease the ROP to 2 ft/hr. While slowly drilling the last part of the section, penetration would be stopped every few feet to circulate bottoms-up to receive samples confirming the shale base; this process requires an additional 24 hours of rig time. After reaching the casing point, the operator would pull out of the hole to pick up logging-while-drilling (LWD) tools to perform a wiping run. This logging, however, is frequently cancelled because of wellbore stability issues, resulting in the loss of important formation-evaluation data across this interval. A new solution has been developed, comprising drilling with a rotary assembly to the final anhydrite marker, then pulling the string out of hole to pick up LWD triple-combo and sonic tools, with a conventional gamma ray sensor placed only 6 ft from the bit. The remaining part of the section would then be drilled at 7-10 ft/hr until the gamma-ray tool detected the shale base, thereby determining the casing depth. In addition, it was planned to re-log the previously drilled interval. This solution prevented the well from potential abandonment and reduced drilling time. It also secured critical formation evaluation data for exploration and future field development. The engineered drilling solution was tried for the first time in these formation sequences within a harsh drilling and logging environment. The option of rotary steerable services with an at-bit GR sensor was not considered because of the high cost.
Kholaif, Yasser (NOSPCO) | Elmaghraby, Mahmoud (NOSPCO) | Nago, Annick (Baker Hughes) | Embry, Jean-Michel (Baker Hughes) | Basu, Pramit (Baker Hughes) | Perumalla, Satya (Baker Hughes) | El-Said, Mohamed M. (Baker Hughes) | ElMenshawy, Ali (Baker Hughes) | Baghdadi, Ahmed (Baker Hughes)
Abstract Drilling challenges in offshore Nile Delta have been largely documented in the literature. Operators are often confronted with drilling problems related to shale swelling, cavings, tight holes in combination with increased risks of lost circulation in some of the highly depleted formations. The Kafr El Sheikh shale in particular, has been linked to many instances of wellbore instability, due to its mineralogical composition (estimated to be mostly smectite, >70%). From offset well drilling experience, it could also be noticed that insufficient mud weight was often used to drill through the Kafr El Sheikh Shale, causing wellbore failure in shear due to lack of support of the wellbore wall. In the past, multiple mud weight designs have been implemented relying solely on pore pressure as lower bound of the mud window. With the increased use of geomechanics, it has been demonstrated that the lower bound should be taken as the maximum of the pore pressure and borehole collapse pressure, thus accounting for the effects of formation pressure, horizontal and vertical stresses, rock properties as well as wellbore trajectory. It has been proven that slight overpressure is often encountered halfway through the Kafr El Sheikh formation, which would typically result in slightly higher borehole collapse pressures. In the study fields, the operator expressed interest in drilling highly deviated wells (> 60-70 degrees). This raised concerns for increased drilling challenges, especially in the Kafr El Sheikh. A comprehensive and systematic risk assessment, design of a fit-for-purpose solution and its implementation during drilling took place in the fields of interest. Offset well data analytics from the subject fields supported a holistic evaluation of drilling risks associated with the Kafr El Sheikh, providing good understanding of stress sensitivity on deviation, azimuth and lithology. Upon building a robust geomechanical model, calibrated against offset well drilling experience, pre-drill mud weight and drilling practices recommendations were provided to optimize the drilling program. Near real-time geomechanical monitoring was implemented which helped to manage the model uncertainties. The implementation of a holistic risk assessment, including geomechanical recommendations and near real-time geomechanical monitoring, was effective to lead the drilling campaign successfully. As a result, three high angle wells (> 60-70 degrees) were drilled through the challenging Kafr El Sheikh formation without any hole instability. An integrated risk assessment of hole instability, managed in stages (pre-drill and during drilling), has helped to understand and simulate the behaviors of the formation. Proactive decisions have established a controlled drilling environment for successful operations.
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.