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Something that struck Brian Price as odd when he started selling chemicals to shale producers a few years ago was how few of them were thinking about whether the fracturing additives they pumped might cause trouble downhole. The man who is now vice president of technology and strategic optimism at Rockwater Energy Solutions--yes, it is optimism--had spent years working offshore. Engineers working in the Gulf of Mexico worried about the possible impact of chemicals pumped into highly permeable sandstone reservoirs made up of minerals such as quartz and feldspar. Both are fairly inert compared to the highly reactive mix in shale formations. While the job of offshore teams is to methodically consider how to maximize production from a few high-cost wells that are expected to produce for decades, those in the shale business have used standard designs to mass-produce wells in bad-quality rock, with a goal of maximizing production in year one.
Data-driven decisions powered by machine-learning (ML) methods are increasing in popularity when optimizing field development in unconventional reservoirs. However, because well performance is affected by many factors, the challenge is to uncover trends within all the noise. By leveraging basin-level knowledge captured by big data sculpting, integrating private and public data with the use of uncertainty quantification, a process the authors describe as augmented artificial intelligence (AI) can provide quick, science-based answers for well spacing and fracturing optimization and can assess the full potential of an asset in unconventional reservoirs. A case study in the Midland Basin is detailed in the complete paper. Augmented AI is a process wherein ML and human expertise are coupled to improve solutions.
NexTier Oilfield Solutions is emerging into a role as consolidator in the fragmented US pressure pumping market by acquiring Alamo Pressure Pumping in a cash-and-stock transaction worth $268 million. The deal, which is expected to be completed by 31 August, brings together two leading providers of low-carbon well completion solutions in the Permian Basin. NexTier itself was born from the merger of C&J Energy Services and Keane Group in late 2019. The Alamo fleet comprises nine, primarily CAT Tier IV, young hydraulic fracturing units. The acquired assets comprise 460,000 horsepower, around 92% of which is Tier IV DGB (dynamic gas blending) capable.
The carbon-free future should not be confused with a utopian future. A zero-carbon world will include the difficult realities experienced in Texas in February 2021. As shown in a graph of US EIA data, during the recent extreme cold event in Texas, wind and solar could not hold flat compared with their baseline the week before (4–8 February). Coal and nuclear remained mostly steady, while natural-gas producers ramped up supplies delivered to power plants by a factor of 4, helping people who were struggling to heat their homes. Natural gas may not receive well-deserved recognition from some quarters, and blackouts and loss of life still occurred, but our industry stepped up when people needed us most.
Interwell tracer tests are widely used. This article reviews some of the studies reported in open literature. The selection introduces different problems that have been addressed, but the original papers should be studied to obtain a more detailed description of the programs. The Snorre field is a giant oil reservoir (sandstone) in the Norwegian sector of the North Sea. Injection water and gas were monitored with tracers, 18 and the resulting tracer measurements are discussed in this page.
Well-to-well tracer tests contribute significantly to the reservoir description, which is essential in determining the best choice of production strategy. Direct dynamic information from a reservoir may be obtained, in principle, from three sources: production history, pressure testing, and tracer testing. The value and importance of tracer tests are broadly recognized. Tracer testing has become a mature technology, and improved knowledge about tracer behavior in the reservoir, improved tracer analysis, and reduction of pitfalls have made tracer tests reliable. Many tracer compounds exist; however, the number of suitable compounds for well-to-well tracers is reduced considerably because of the harsh environment that exists in many reservoirs and the long testing period. Radioactive tracers with a half-life of less than one year are mentioned only briefly in this chapter because of their limited applicability in long-term tests. Tracers may be roughly classified as passive or active. In principle, a passive tracer blindly follows the fluid phase in which it is injected. Interpretation of tracer-production curves must account for this. The results from the application of active tracers may give information about fluid saturation and rock surface properties. This information is especially important when enhanced-oil-recovery techniques that use expensive fluids such as surfactants, micellar fluids, or polymers are considered. In the last 50 years, many tracer studies have been reported and even more have been carried out without being published in the open literature. Wagner pointed out six areas in which tracers could be used as a tool to improve the reservoir description. Many companies apply tracer on a routine basis. The reservoir engineer's problem generally is a lack of adequate information about fluid flow in the reservoir. The information obtained from tracer tests is unique, and tracer tests are a relatively cheap method to obtain this information. The information is an addendum to the general field production history and is used to reduce uncertainties in the reservoir model. Tracer tests provide tracer-response curves that may be evaluated further to obtain relevant additional information. Primarily, the information gained from tracer testing is obtained simply by observing breakthrough and interwell communication.
As one of the first fields in the world to use carbon dioxide (CO2) in enhanced oil recovery (EOR), the Scurry Area Canyon Reef Operators Committee (SACROC) unit of the Kelly-Snyder field in the Midland Basin of Texas provides a unique opportunity to study, learn from, and improve upon the development of CO2 flood technology. The complete paper reviews the history of EOR at SACROC, discusses changes in theory over time, and provides a look at the field's future. The first six pages of the paper discuss the field's location, geology, and development before June 2000, when Kinder Morgan acquired the SACROC unit and took over as operator. Between initial gas injection in 1972 and 2000, approximately 1 TCF of CO2 had been injected into the Canyon Reef reservoir. Since 2000, cumulative CO2 injection has surpassed 7 TCF and yielded cumulative EOR of over 180 million bbl.
A long time ago, my mentor, Farooq Ali, wrote a thought-provoking paper on the unfulfilled promises of enhanced oil recovery (EOR). His essential summary: EOR had not lived up to its hype and full potential. There were more than a hundred methods and techniques proposed, but only a few had succeeded commercially. Fast-forward a few decades and into the new century, and the message and conclusions have not changed. EOR has definitely not lived up to its promise, especially from the big-picture perspective of daily oil production rates.
Free data from the first Permian Hydraulic Fracturing Test Site is available online and reports from the second test site will be available this summer. Those reports offer a unique look at fracturing in the Midland and Delaware Basins, using nearly every diagnostic test an engineer can think of and analysis by technology leaders including Occidental and Shell among the partners. Because the US government shares the cost with industry partners, the data are made publicly available after a period during which the companies that pay half the cost have exclusive access to it. The data posted draw on work begun more than 5 years ago. It is available on the National Energy Technology Laboratory's EDX data sharing site (details below). The files offer processed data from testing done at an 11-well pad in the Midland Basin dating back to 2015, said Gary Covatch, a petroleum engineer at the US Department of Energy.
El-Husseiny, Mahmoud Ahmed (Egyptian Natural Gas Holding Company) | Khaled, Samir Mohamed (AL-Azhar University and the British University in Egypt.) | El-Fakharany, Taher El-Sebaay (AL-Azhar University.) | Al-Nadi, Yehia Mohamed (AL-Azhar University.)
Abstract Although devised in 2003, managed pressure drilling (MPD) has gained widespread popularity in recent years to precisely control the annular pressure profile throughout the wellbore. Due to the relatively high cost and complexity of implementing MPD, some operators still face a challenge deciding whether or not to MPD the well. In the offshore Mediterranean of Egypt, severe to catastrophic mud losses are encountered while conventionally drilling deepwater wells through cavernous fractured carbonate gas reservoirs with a narrow pore pressure-fracture gradient (PP-FG) window, leading to the risk of not reaching the planned target depth (TD). Furthermore, treating such losses was associated with long non-productive time (NPT), massive volume consumption of cement, and lost-circulation materials (LCM), in addition to well control situations encountered several times due to loss of hydrostatic head during severe losses. Accordingly, the operator decided to abandon the conventional drilling method and implement MPD technology to drill these problematic formations. In this paper, the application of MPD is to be examined versus the conventional drilling in terms of well control events, NPT, rate of penetration (ROP), mud losses per drilled meter, LCM volume pumped, and drilling operations optimization. According to the comparative study, MPD application showed a drastic improvement in all drilling performance aspects over the conventional drilling where the mud losses per drilled meter reduced from 19.6 m/m to 3.7m/m (123.2 bbl/m to 23.4 bbl/m). In addition to that, a 35% reduction of NPT and also a 35% reduction of LCM pumped, and 67.2 % reduction by volume of cement pumped to cure the mud losses. Moreover, the average mechanical rate of penetration increased by 37.4%. MPD was also credited with eliminating the need for an additional contingent 7" liner which was conventionally used to isolate the thief zone. The MPD ability to precisely control bottom hole pressure during drilling with the integration of MPD early kick detection system enables the rapid response in case of mud loss or kick, eliminating kick-loss cycles, well control events, and drilling flat time to change mud density. This paper provides an advanced and in-depth study for deep-water drilling problems of a natural gas field in the East Mediterranean and presents a comprehensive analysis of the MPD application with a drilling performance assessment (average ROP, mud losses, LCM and cement volumes, well control events) emphasizing how MPD can offer a practical solution for future drilling of challenging deepwater gas wells.