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Oil and gas executives across the North American shale sector are continuing to come to the table and negotiate a steady stream of deals to consolidate portfolios. During the second quarter, the deal making amounted to more than $33 billion in mergers and acquisitions, according to data from Enverus. The energy-focused analytics firm said last month in its quarterly review the combined figure represents more than 40 deals, with seven of them topping $1 billion each. The third quarter has so far not seen any announced transactions surpass the $1-billion mark. Instead, most deals struck in July were between mid-sized and small US-based operators.
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.
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.
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.
Potapenko, Dmitriy Ivanovich (Member) | Hart, Timothy Brian (Fremont Petroleum Corporation) | Waters, George Alan (Member) | Lewis, Richard E. (Member) | Utter, Robert J. (New Ventures Energy Consulting) | Brown, J. Ernest (Member) | Goudy, Guy Thomas (Formerly Fremont Petroleum Corporation) | Jelsma, Henk H (Radial Drilling Services, Inc.)
Abstract This paper describes the first application of a novel reservoir-stimulation methodology that combines oriented extended perforation tunnels of lengths up to 300 feet with specially designed hydraulic fracturing operations in the Niobrara Formation in the Florence Field in Colorado. The technology was extensively tested in two vertical wells completed with two and five pairs of the extended perforation tunnels respectively. Extended perforation tunnels were jetted using radial drilling technique with the tools deployed using micro coil tubing. The jetting operation on each well was followed by a fracture stimulation treatment. The use of radial drilling technology to create extended perforation tunnels for the vertical wells offered a cost-effective way to significantly increase the reservoir contact area of the wellbore, making it similar to that of horizontal wells in the area. The engineered fracture treatments were performed at low treating pressures, and low proppant and fluid volumes. The stabilized production rates of both project vertical wells included in this technology test exceeded expectations and are comparable to the stabilized production rate of the offset horizontal well that was completed in the same zone with significantly higher volumes of proppant and fluid. The initial evaluation of the completion efficiency of this novel reservoir stimulation technology showed that its deployment delivered an improved stabilized production rate to cost ratio for the second vertical well, compared to the reference horizontal well. Based on the test results from the two wells, we conclude that the proposed reservoir stimulation methodology leads to substantial improvements in well production performance compared to traditional reservoir stimulation methods. Both the applied cost-effective approach for increasing the reservoir contact and the significantly lower resource intensity required for the hydraulic fracturing treatment further improve the economic benefits of this methodology. This novel reservoir stimulation methodology opens the way for reconsidering well completion practices in the Niobrara Formation and holds significant potential for improving the hydrocarbon production economics in the Florence Field.
The Rumaila Field is in southeast Iraq and contains multiple reservoir intervals, including the Upper Cretaceous Mishrif carbonate reservoir, one of the major reservoirs in the world, that has been producing for more than 50 years. One of the key challenges in the Mishrif is to characterize the pore-structure distinction between primary and secondary porosity. The secondary porosity in the form of large pores, if present, dominates the petrophysical properties, especially permeability. Advanced logs, e.g., nuclear magnetic resonance (NMR) and image logs, can be used to understand the variations in pore structure, both qualitatively and quantitatively. In this paper, we focused primarily on four new wells with very comprehensive logging and coring programs. NMR logs were acquired using different tools and pulse sequences. This resulted in uncertainty in porosity and T2 distributions and, consequently, complications in the NMR interpretation. We observed two key issues: porosity deficit due to lack of polarization and T2 distribution truncation due to the low number of echoes. We used a single pore model to reproduce the NMR response in different pore sizes and fluid types for different pulse sequences. The results showed that the NMR response, especially in water-filled (water-based-mud filtrate) large pores, is sensitive to polarization time, echo spacing, and tool gradient strength. NMR log data confirmed the modeling results. We recommended an optimum pulse sequence and tool characteristics to fully capture the heterogeneous rock and fluid system in this carbonate reservoir. NMR logs, when available, were the primary tools to identify the large pores. We present a consistent workflow for NMR log analysis that was developed to identify and quantify large pores and extended to all wells in the field. We used advanced NMR interpretation techniques, e.g., factor analysis (NMR FA) (Jain et al., 2013), in a series of oil wells drilled with water-based mud. Using factor analysis, we identified a cutoff value of 847 ms for large pore volumes. In this manuscript, we also present an integration of laboratory measurements, e.g., NMR, mercury intrusion capillary pressure (MICP) data, whole-core CT scanning, and thin-section analysis, in our interpretation workflow. We also compared the large pore volume from image logs with NMR logs and other laboratory data and observed very consistent results. All the available information was integrated to build an “NMR-based” petrophysical model for porosity, rock type, permeability, and saturation determination. The NMR-based model was very comparable with the classic flow zone indicator (FZI) rock typing. The results of this study were used to modify the NMR acquisition program in the field and to build a petrophysical model based on only NMR and image log measurements for carbonate reservoirs. In this paper, we will discuss NMR modeling and corresponding log data from various wells to confirm the results. Furthermore, we will present a novel interpretation workflow integrating laboratory measurements and log data, which led to the modification of the NMR acquisition program in the field and the creation of a data-driven petrophysical model based on only NMR and image log measurements for carbonate reservoirs.
Abstract Cleanouts and milling make up most of the common coiled tubing (CT) operations around the globe. The objective of each is to remove debris from a wellbore, such as sand, scale, cement, or fracture plugs, to promote an unobstructed flow path for fluids. For decades, operators and service companies have focused heavily on methods to optimize removal of debris through the development of specialized tools, fluids, techniques, and predictive models. These are coupled with wellsite equipment digital acquisition systems to capture CT behavior, pump rates, and chemical additive rates; very little attention has been given to the rates of the fluid and solids being returned to surface. The composition and quality of fluids being pumped into the well are often well characterized, and the pump rate is recorded digitally to the second. By contrast, information on the fluid being returned is frequently limited to intermittent, manual surveys of the flowback tank fluid level that often go unrecorded. Fluid samples are rarely analyzed, even by inexact measurements, to provide feedback to the predictive model. This results in a missed opportunity to optimize the operation as well as to recognize and respond to undesirable trends and actions in real time. This paper describes a simple digital acquisition system developed and implemented in the field to digitally record, plot, and monitor critical wellsite parameters including flowback rate, solids returns, annular velocities, and downhole Reynolds numbers. The system provides a real-time visual aid to observe the direct impact that operational decisions have on cleanout efficiency and the opportunity to correct and optimize the cleanout operation. Furthermore, the system offers the opportunity to rapidly recognize and respond to unexpected trends such as a gradual or sudden loss in return rate or a decrease of solids returns which could rapidly result in serious consequences such as a stuck-pipe situation.
Summary “Fracture hit” was initially coined to refer to the phenomenon of an infill-well fracture interacting with an adjacent well during the hydraulic-fracturing process. However, over time, its use has been extended to any type of well interference or interaction in unconventional reservoirs. In this study, an exhaustive literature survey was performed on fracture hits to identify key factors affecting the fracture hits and suggest different strategies to manage fracture hits. The impact of fracture hits is dictated by a complex interplay of petrophysical properties (high-permeability streaks, mineralogy, matrix permeability, natural fractures), geomechanical properties (near-field and far-field stresses, tensile strength, Young’s modulus, Poisson’s ratio), completion parameters (stage length, cluster spacing, pumping rate, fluid and proppant amount), and development decisions (well spacing, well scheduling, fracture sequencing). It is difficult to predict the impact of fracture hits, and they affect both parent and child wells. The impact on the child wells is predominantly negative, whereas the effect on parent wells can be either positive or negative. The “child wells” in this context refer to the wells drilled with pre-existing active/inactive well(s) around. The “parent well” refers to any well drilled without any pre-existing well around. Overall, fracture hits tend to negatively affect both the production and economics of lease development. The optimal approach rests in identifying the reservoir properties and accordingly making field-development decisions that minimize the negative impact of fracture hits. The different strategies proposed to minimize the negative impact of fracture hits are simultaneous lease development, thus avoiding parent/child wells (i.e., rolling-, tank-, and cube-development methods); repressuring or refracturing parent wells; using far-field diverters and high-permeability plugging agents in the child-well fracturing fluid; and optimizing stage and cluster spacing through modeling studies and field tests. Finally, the study concludes with a recommended approach to manage fracture hits. There is no silver bullet, and the problem of fracture hits in each shale play is unique, but by using the available data and published knowledge to understand how fractures propagate downhole, measures can be taken to minimize or even completely avoid fracture hits.