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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.
Water is the most commonly used fluid in hydraulic fracturing, and it is used in large quantities. Chemicals are added to the water to aid in fracturing and prevent damage to the reservoir, and normally less than 1 percent of the fluid contents are chemical compounds. Because fracturing involves a large amount of water, innovations to reuse/recycle and safely dispose of the water are an important part of environmental stewardship. Hydraulic fracturing is the process of pumping fluid into a wellbore at an injection rate too high for the formation to accept without breaking. During injection, the formation's resistance to flow increases, and the pressure in the wellbore increases to a value called the break-down pressure, which is the sum of the in-situ compressive stress and the strength of the formation.
Water sources are treated for disposal, injection as a liquid, or injection as steam with three types of facilities. Produced water is treated in offshore operations for overboard disposal or injection into a disposal well. Water sources are treated for disposal, injection as a liquid, or injection as steam with three types of facilities. Surface water is treated offshore for liquid injection and onshore for liquid- or steam-injection purposes. In all instances, the surface water must be cleaned of dispersed and dissolved solids to a level suitable for reservoir or steam-generation purposes.
Documentaries are used both to educate and tell stories that their makers believe should be heard. That applies to documentaries about the inner workings of various industries such as oil and gas. To many outside the petroleum industry, those inner workings are a black box: Money and engineering goes in, gasoline and petrochemical products come out. It is also full of stories, making it an industry ripe for documentarians. The following reviews consider a small handful of the documentaries covering the petroleum industry and what might be learned from them beyond their immediate message.
Explaining Traditional Engineering Models It is a well-known fact that models of physical phenomena that are generated through mathematical equations can be explained. This is one of the main reasons behind the expectation of engineers and scientists that any potential model of the physical phenomena should be explainable. Explainability of the traditional models of physical phenomena is achieved through the solutions of the mathematical equations that are used to build the models. Explanations of such models are achieved through analytical solutions (for reasonably simple mathematical equations) or numerical solutions (for complex mathematical equations) of the mathematical equations. Solutions of the mathematical equations provide the opportunities to get answers to almost any question that might be asked from the model of the physical phenomena. Solutions of the mathematical equations are used to explain why and how certain results are generated by the model. It allows examination and explanation of the influence and effect of all the involved parameters (variables) on one another and on the model's results (output parameters).
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.
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.
Johnson, Andrew C. (Schlumberger) | Miles, Jeffrey (Schlumberger) | Mosse, Laurent (Schlumberger) | Laronga, Robert (Schlumberger) | Lujan, Violeta (Schlumberger) | Aryal, Niranjan (Schlumberger) | Nwosu, Dozie (Schlumberger)
Abstract Formation water saturation is a critical target property for any comprehensive well log analysis program. Most techniques for computing saturation depend heavily on an analyst’s ability to accurately model resistivity measurements for the effects of formation water resistivity and rock texture. However, the pre-requisite knowledge of formation water properties, particularly salinity, is often either unknown, varying with depth or lateral extent, or is difficult to derive from traditional methods. A high degree of variability may be present due to fluid migration from production, water injection, or various geological mechanisms. In unconventional reservoirs, the complexity of the rocks and pore structure further complicates traditional interpretation of the available well logs. These factors introduce significant uncertainties in the computed fluid saturations and therefore can substantially affect final reserves estimates. A novel technique in geochemical spectroscopy has recently been introduced to distinguish the chlorine signals of the formation and borehole. The new, quantitative measurement of formation chlorine enables a direct calculation of bulk water volume for a given formation water salinity. When integrated into a multi-physics log analysis workflow, the chlorine-derived water volume can provide critical information on fluid saturations, hydrocarbon-in-place, and producibility indicators. This additional information is especially useful for characterizing challenging and complex unconventional reservoirs. We present the new technique through several full petrophysical evaluation case studies in organic shale formations across the U.S., including the Midland, Delaware, Marcellus, and DJ basins. We solve for formation-specific water salinity and bulk water volume through an optimization that combines chlorine concentration with resistivity and dielectric measurements. These outputs are integrated into comprehensive petrophysical evaluations, leveraging a suite of advanced well log measurements to compute final fluid and rock properties and volumetrics. The evaluations include geochemical mineralogy logs, 2D NMR analyses, dielectric dispersion analyses, basic log measurements, and multi-mineral models. The results underscore the utility of the new spectroscopy chlorine log to reduce petrophysical model uncertainties in an integrated workflow. While this workflow has been demonstrated here in several U.S. organic shale case studies, the fundamental challenges it addresses will make it a valuable solution for a range of unconventional reservoirs globally.
Swiss oil trader Vitol said on 30 April that its oil and gas subsidiary, Vencer Energy, was buying Hunt Oil Company's assets in the Permian Basin for an undisclosed sum. Media outlets including Bloomberg and Reuters cited sources that pegged the asking price at around $1 billion. Houston-based Vencer was established last year as the trading giant's first foray into the upstream sector. The assets include leases on 44,000 acres in the Midland Basin side of the Permian, with an output about 40,000 BOE/D. "This is an important day for Vencer as it establishes itself as a significant shale producer in the US Lower 48. We expect US oil to be an important part of global energy balances for years to come, and we believe this is an opportune time for investment into an entry platform in the Americas," said Ben Marshall, the head of Vitol's Americas business unit.