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Michael Eberhard, an SPE Distinguished Service Award recipient and former director of the SPE Rocky Mountain Region, died 23 June. Eberhard started his 40-year oil industry career as a field engineer for Halliburton Services. He went on to become the company's Rocky Mountain Technology Manager from 2004 to 2011 and led a multidisciplined team focused on unconventional resources completions and optimization. He was the completions manager for Anadarko Petroleum's DJ Basin program from 2011 to 2015. He joined SRC Energy in 2015 and was the COO and executive vice president of the company.
Introduction Petroleum data analytics is a solid engineering application of data science in petroleum-engineering-related problems. The engineering application of data science is defined as the use of artificial intelligence and machine learning to model physical phenomena purely based on facts (e.g., field measurements and data). The main objective of this technology is the complete avoidance of assumptions, simplifications, preconceived notions, and biases. One of the major characteristics of petroleum data analytics is its incorporation of explainable artificial intelligence (XAI). While using actual field measurements as the main building blocks of modeling physical phenomena, petroleum data analytics incorporates several types of machine-learning algorithms, including artificial neural networks, fuzzy set theory, and evolutionary computing.
Denver-based Civitas Resources announced today that it is acquiring Crestone Peak Resources in an all-stock transaction. Civitas was formed last month through the announced merger of Denver-Julesburg (DJ) Basin operators Bonanza Creek Energy and Extraction Oil & Gas. On a pro forma basis, the three-way merger will create a firm with an enterprise value of nearly $4.5 billion and a production profile of almost 160,000 BOE/D. Crestone's assets will bring Civitas' position in the DJ Basin to more than 500,000 net acres. In addition, the combination with Crestone is expected to realize nearly $45 million in expected annual synergies.
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.
Abstract Subsurface characterization of fluid volumes is typically constrained and validated by core analytical fluid saturation measurement techniques (example Dean-Stark or Open Retort methodology). As production in resource plays has progressed over time, it has been noted that many of these methods have a large error when compared to production data. A large source of the error seems to be that water saturations in tight rocks have been consistently underestimated in the traditional laboratory measurement techniques. Operators need improved fluid saturation measurements to better constrain their log-based oil-in-place estimates and forward-looking production trends. The overall goal of this study is to test a new laboratory workflow for fluid saturation quantification. Recent advancements have led to an innovative methodology where a closed retort laboratory technique is applied to samples from lithological rock types in the Williston, Uinta and Denever-Julesburg (DJ) basins. This new technique is specifically designed to better quantify and validate water measurements throughout the tight rock analysis process, as well as improved oil recovery and built-in prediction. A comparison of standard crushed rock analysis employing Dean-Stark saturation methods is compared to the closed retort results and observations discussed. Results will also be compared against additional laboratory methods that validate the results such as geochemistry and nuclear magnetic resonance. Finally, open-hole wireline logs will be utilized to quantify the impact on total water saturation and the oil-in place estimates based on the improved accuracy of the closed retort technique.
Zhang, D. Leslie (CNPC USA Corp.) | Qi, Chunyan (Beijing Huamei Century International Technology Co.) | Shi, Xiaodong (Exploration and Development Research Institute of Daqing Oilfield Company Ltd.) | Zhan, Jianfei (Exploration and Development Research Institute of Daqing Oilfield Company Ltd.) | Han, Xue (Exploration and Development Research Institute of Daqing Oilfield Company Ltd.) | Li, Xiangyun (Beijing Huamei Century International Technology Co. Ltd.) | Wang, Ze (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Abstract Relative permeability is one of the most important petrophysical parameters to evaluate a reservoir’s production during primary and subsequent secondary or enhanced oil recovery processes. Yet measured relative permeability data for tight oil reservoirs are very scarce to find in the literature, mainly because the measurement is difficult and time consuming to make. In this paper the protocol and results of water/oil, surfactant /oil, CO2/oil, and N2/oil relative permeability are presented, and compared to the digital core analysis results where wettability was set to water-wet or mixed-wet, as well as the Brooks-Corey model. Amott-Harvey wettability index was measured to explain the differences. The target formation is a sandstone tight oil formation located in Songliao Basin, China. Its permeability is mostly in the 0.01-5mD range. Core and oil samples from the target formation were used in the wettability and relative permeability determination. Relative permeability was measured at reservoir conditions using a customized core flow setup. Core samples were cleaned then wettability restored. To match the reservoir fluid viscosity and avoid changing wettability, stock tank oil was blended with kerosene to reservoir fluid viscosity at reservoir temperature. Relative permeability was measured using the unsteady-state method. Amott-Harvey wettability index was measured on core samples from the same formation at reservoir temperature. Amott-Harvey wettability index results show that the restored wettability ranged from water-wet to oil-wet, with most samples being mixed-wt. The addition of non-ionic surfactant promoted wettability change toward more water-wetness. However, anionic surfactant had little effect on reversing wettability. Oil relative permeability (Kro) results obtained from the digital rock analysis (DRA) assuming uniform water-wetness are consistent with relative permeability calculated from mercury injection capillary pressure using Brooks-Corey model. When wettability of the digital rock model was set to mixed-wet, the resulted Kro matches the measured Kro of a sister plug to the sample used to build the digital rock model, which is consistent with the wettability measurements. The addition of surfactants increased both water and oil relative permeability through wettability alteration and IFT reduction. CO2 flood was conducted as an immiscible flood due to reservoir pressure lower than MMP. CO2 flood left high residual oil saturation compared with water floods. N2 flood left even more oil behind compared with CO2 flood. Relative permeability provides key input parameters for formation evaluation and the subsequent EOR processes such as huff-n-puff operations. There are very little published relative permeability data for tight oil reservoirs. This work extends the relative permeability database, and is a starting point for future EOR work.
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.
Abstract Petrophysicists often find sonic velocities difficult to interpret, especially when choosing values for the mineral and fluid endpoints. This difficulty is always caused by stress sensitive formations where dipole sonic velocities vary with stress, even when the petrophysical properties are constant. The goal of this coupled workflow is to quantify the compositional influences of porosity, mineralogy, and fluids, while isolating and quantifying the geomechanical influence of stress. I first estimate the petrophysical properties using a standard multi-mineral petrophysical solver void of sonic inputs. This allows one to independently observe and quantify variations in both compressional and shear velocities with variations in petrophysical properties. I then normalize the sonic velocities to an idealized formation having compositional properties constant with depth by applying both matrix and fluid substitution algorithms. If these normalized velocities are constant with depth, then the formations are insensitive to stress, and I apply the standard petrophysical workflow using the measured sonic inputs. In addition, the standard geomechanical workflow that assumes linear elasticity is appropriate to estimate the in-situ stresses. However, if the normalized velocities vary with depth, the formations are sensitive to stress, which requires modifications to both the standard petrophysical and geomechanical workflows. Specifically, one must quantify and remove the velocity variations due to stress or else misinterpret velocity changes due to stress for changes in petrophysical properties. For formations sensitive to stress, I quantify the stress sensitivity by using the observed change in normalized velocity with depth with an estimate of the change in stress with depth. I then compute a second velocity normalization that quantifies and removes the acoustical sensitivity to stress in favor of a constant reference stress. I can now more accurately quantify the petrophysical properties by including the stress normalized velocities in the multi-mineral petrophysical solver. At this point in the workflow, there are two methods for quantifying the in-situ horizontal stress. The first method uses the velocities normalized to the constant reference stress to compute the dynamic elastic moduli. These dynamic elastic moduli are now appropriate to input into the standard geomechanical workflow. The second method uses the velocities normalized for the changing petrophysical properties, together with the stress sensitivity coefficients, to directly invert the velocities for the in-situ horizontal stresses. A comparison between the two methods supplies a consistency check. I emphasize both methods require in-situ horizontal stress calibration data for correct results. To clearly illustrate the workflow, this paper specifies the mathematical formulations with example calculations. This coupled workflow is novel because it highlights and clarifies improper assumptions while acknowledging the rock physics of stress sensitive formations. In the process, it improves the accuracy of both the derived petrophysical properties and geomechanical stresses.
Sochovka, Jon (Liberty Oilfield Services) | George, Kyle (Liberty Oilfield Services) | Melcher, Howard (Liberty Oilfield Services) | Mayerhofer, Mike (Liberty Oilfield Services) | Weijers, Leen (Liberty Oilfield Services) | Poppel, Ben (Liberty Oilfield Services) | Siegel, Joel (Liberty Oilfield Services)
Abstract The shale industry has changed beyond recognition over the last decade and is once again in rapid transition. While we are unsure about the nature of innovations to make US shale ever more competitive, we are certain that the current downturn will drive a further reduction in $/BO – the total cost to lift a barrel of US shale oil to the surface. As a result of an increase in scale and industry efficiency gains, the all-in price charged by service companies to place a pound of proppant downhole has come down from more than $0.50/lb in 2012 to about $0.10/lb today. In this paper, we discuss what components have contributed to this reduction to date and use several case studies to illustrate the potential for further cost reductions. The authors used FracFocus data to study a variety of placement and production chemicals for about 100,000 horizontal wells in US liquid rich basins, including the Williston, Powder River, DJ, Permian basins, as well as SCOOP/STACK and Eagle Ford. All chemicals used were averaged on a per-well basis into a gallon-per-thousand gallons (gpt) metric. In the paper, we first provide an overview of trends by basin since 2010 for these chemical additives. Then, we perform Multi-Variate Analysis (MVA) to determine if groups of these chemicals show an impact on production performance in specific basins or formations. Finally, through integration of lab testing (on fluid systems and proppants), a liquid-rich shale production database and FracFocus tracking of industry trends, the authors developed a list of case histories that show modest to significant reductions in $/BO. In this paper we focus on proppant delivery cost – the cost to place a pound of proppant in a fracture downhole, where it can contribute to a well's production for years to come. The last decade saw a 10-fold increase in horsepower, a 20-fold increase in yearly stages pumped and a 40-fold yearly proppant mass increase. One result of this increase in scale, was a gain in efficiencies, which led to an average 3-fold fracturing cost decrease to place a pound of proppant downhole. We will document this trend in detail in the paper. A significant industry trend over the last decade has been a "viscosity for velocity" trade. The change to smaller mesh regional proppants, in combination with an increase in pump rates on frac jobs in the US, has allowed fluid systems to become more "watery". At the same time, the industry is moving from guar systems to polyacrylamide-based systems that exhibit higher apparent viscosities at low to ultra-low shear rates. These newer High Viscosity Friction Reducer (HVFR) systems show superior proppant carrying capacity over traditional slickwater fluid systems. Regained conductivity testing has shown that these HVFR systems are generally cleaner for fracture conductivity than guar systems. Along with changes to base chemistry, a 2- to 5-fold increase in disposal costs and an overall "green initiative" over the last decade have resulted in a push to maximize recycled water usage on these HVFR jobs. These waters can be in excess of 150,000 TDS (Total Dissolved Solids) which present challenges across the board when designing a compatible fluid system that fits the needs in terms of viscosity yield, scale inhibition and microbial mitigation etc. – all while keeping costs low. Specialty chemicals, such as Hydrochloric Acid (HCl) substitutes that have similar efficacy as HCl but significantly lower reactivity with human skin, have helped significantly to improve operational safety around previously-categorized hazardous chemicals, and have helped reduce cost and improve pump time efficiency. Measurement of bacterial activity during and after fracture treatments can help with the best economic selection of the appropriate biocide. These simple measurements can help further reduce what is spent on the necessary chemical package to effectively treat a well. This paper provides a holistic view of fluid selection issues and shows a real-data focused methodology to further support a leaner approach to hydraulic fracturing.
Abstract A seven-step workflow to help subsurface teams establish an initial thesis for optimal completion design (cluster spacing, proppant per cluster) and well spacing in emerging / under-explored resource plays is proposed and executed for the Powder River Basin Niobrara unconventional oil play. The workflow uses Rate Transient Analysis (RTA) to determine the parameter and then walks the reader through how to sequentially decouple the parameter into its constituent parts (frac height (h), number of symmetrical fractures achieved (nf), permeability (k) and fracture half-length (xf)). Once these terms were quantified for each of the case study wells, they were used in a black oil reservoir simulator to compare predicted verses actual cumulative oil performance at 30, 60, 90,120 & 180 days. A long-term production match was achieved using xf as the lone history match parameter. xf verses proppant per effective half-cluster yielded an R value of > 0.90. 28 simulation scenarios were executed to represent a range of cluster spacing, proppant per cluster and well spacing scenarios. Economics (ROR and/or NPV10/Net Acre) were determined for each of these scenarios under three different commodity pricing assumptions ($40/$2.50, $50/$2.50 and $60/$2.50). An initial thesis for optimal cluster spacing, proppant per designed cluster and well spacing were determined to be 12’, 47,500 lbs and 8-14 wells per section (based on whether or not fracture asymmetry is considered) when WTI and Henry Hub are assumed to be $50 & $2.50 flat.