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The price of adding oil in shale plays will be rising this fall as the supply of wells that were drilled but uncompleted (DUCs) runs low. In the top five US shale plays, the total has dropped from more than 6,300 DUCs at the peak in the spring of 2020 to around 4,500 now, according to a report from Rystad Energy. That is the lowest since the fall of 2018 when oil prices were far lower than the current $70/bbl. Back then, the current price would have caused drilling to explode and production to rise, but not this year. Drilling is up this year from last year's deep slump, but it is just keeping up with the declines in older wells.
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.
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 Well spacing and stimulation design are amongst the highest impact design variables which can dictate the economics of an unconventional development. The objective of this paper is to showcase a numerical simulation workflow, with emphasis on the hydraulic fracture simulation methodology, which optimizes well spacing and completion design simultaneously. The workflow is deployed using Cloud Computing functionality, a step-change over past simulation methods. Workflow showcased in this paper covers the whole cycle of 1) petrophysical and geomechanical modeling, 2) hydraulic fracture simulations and 3) reservoir simulation modeling, followed by 4) design optimization using advanced non-linear methods. The focus of this paper is to discuss the hydraulic fracture simulation methods which are an integral part of this workflow. The workflow is deployed on a dataset from a multi-well pad completed in late 2018 targeting two landing zones in the Vaca Muerta shale play. On calibrated petrophysical and geomechanical model, hydraulic fracture simulations are conducted to map the stimulated rock around the wellbores. Finely gridded base model is utilized to capture the property variation between layers to estimate fracture height. The 3d discrete fracture network (DFN) built for the acreage is utilized to pick the natural fracture characteristics of the layers intersected by the wellbores. The methodology highlights advances over the past modeling approaches by including the variation of discrete fracture network between layers. The hydraulic fracture model in conjunction with reservoir flow simulation is used for history matching the production data. On the history matched model, a design of experiments (DOE) simulation study is conducted to quantify the impact of a wide range of well spacing and stimulation design variables. These simulations are facilitated by the recent deployments of cloud computing. Cloud computing allows parallel running of hundreds of hydraulic fracturing and reservoir simulations, thereby allowing testing of many combinations of stimulation deigns and well spacing and reducing the effective run time from 3 months on a local machine to 1 week on the cloud. Output from the parallel simulations are fitted with a proxy model to finally select the well spacing and stimulation design variables that offer the minimum unit development cost i.e. capital cost-$ per EUR-bbl. The workflow illustrates that stimulation design and well spacing are interlinked to each other and need to be optimized simultaneously to maximize the economics of an unconventional asset. Using the workflow, the team identified development designs which increase EUR of a development area by 50-100% and reduce the unit development cost ($/bbl-EUR) by 10-30%.
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.
Abstract A few researches have been conducted to study effects of cryogenic treatment (known as thermal shocking) on unconventional rock properties, while they have been extensively studied in geothermal projects. The results show that cryogenic treatment significantly alters the rock mechanical properties by creation of new cracks owing to thermally induced stresses resulting in the permeability enhancement. In this laboratory study, effects of cryogenic treatment (thermal shocking) on permeability and dynamic elastic properties of three Wolfcamp core samples (one outcrop and two downhole samples) at downhole conditions were experimentally evaluated. Permeability and dynamic rock mechanical properties were measured before and after conducting each cycle of thermal shock. Using X-ray powder diffraction (XRD) analysis, the mineral compositions of the cores were determined. The results demonstrate that implementing the thermal shock technique on the core samples results in increasing their permeability and ductility.
Abstract Leveraging publicly available data is a crucial stepfor decision making around investing in the development of any new unconventional asset.Published reports of production performance along with accurate petrophysical and geological characterization of the areashelp operators to evaluate the economics and risk profiles of the new opportunities. A data-driven workflow can facilitate this process and make it less biased by enabling the agnostic analysis of the data as the first step. In this work, several machine learning algorithms are briefly explained and compared in terms of their application in the development of a production evaluation tool for a targetreservoir. Random forest, selected after evaluating several models, is deployed as a predictive model thatincorporates geological characterization and petrophysical data along with production metricsinto the production performance assessment workflow. Considering the influence of the completion design parameters on the well production performance, this workflow also facilitates evaluation of several completion strategies toimprove decision making around the best-performing completion size. Data used in this study include petrophysical parameters collected from publicly available core data, completion and production metrics, and the geological characteristics of theNiobrara formation in the Powder River Basin. Historical periodic production data are used as indicators of the productivity in a certain area in the data-driven model. This model, after training and evaluation, is deployed to predict the productivity of non-producing regions within the area of interest to help with selecting the most prolific sections for drilling the future wells. Tornado plots are provided to demonstrate the key performance driversin each focused area. A supervised fuzzy clustering model is also utilized to automate the rock quality analyses for identifying the "sweet spots" in a reservoir. The output of this model is a sweet-spot map that is generated through evaluating multiple reservoir rock properties spatially. This map assists with combining all different reservoir rock properties into a single exhibition that indicates the average "reservoir quality"of the formation in different areas. Niobrara shale is used as a case study in this work to demonstrate how the proposed workflow is applied on a selected reservoir formation whit enough historical production data available.
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.