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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.
Colorado oil production is surging to record levels, outpacing the other major producing US states in year-over-year gains on the backs of the steady-and-predictable Denver-Julesburg (DJ) Basin and overlapping Niobrara Shale. As overall US oil output continues to surge, attention has been drawn to the Permian Basin and SCOOP and STACK plays. Operators have flocked to West Texas, southeastern New Mexico, and central Oklahoma to stake claims to land they believe will usher them into a new, leaner era for the industry. The expansive Permian alone, which covers more than 75,000 sq miles, has accounted for the bulk of US oil production increases and mergers and acquisitions over the last couple of years. Although they are intertwined and together encompass parts of Colorado border states Wyoming, Nebraska, and Kansas, the DJ and Niobrara offer a fraction of the acreage and prospective resources of the Permian.
Years in the making, the recent steady rise in drilling in the Powder River Basin of northeast Wyoming is generating excitement reminiscent of the early days of currently more-established US onshore oil plays. The upturn in activity is resulting in double-digit production growth. Wells are bubbling over with oil, and operators are bubbling over with enthusiasm. This has been most evident in recent industry presentations, where decision makers from the basin's exclusive club of operators have gushed over what is becoming a core asset in their portfolios. Given the basin's oil richness, multiple stacked horizons, and well performance and economics, "we think it's comparable and competitive with the big-name basins--whether it's the Permian, SCOOP, or STACK," Joseph DeDominic, president and chief operating officer of Anschutz Exploration, said at a recent SPE Gulf Coast Section meeting on the basin.
Colorado voters soundly defeated a measure 6 November that would have restricted the vast majority of new development in the country's fifth largest oil-producing state. The outcome was a big relief for the oil and gas industry, but its existential fight in the state hasn't ended. Proposition 112 would have required new oil and gas development in Colorado to be at least 2,500 ft from areas considered "vulnerable," including homes, schools, and waterways. The current minimum setback is 500 ft. With more than 90% of precincts reporting, about 57% of the electorate voted against the measure.
Abstract Operators and investors are interested in finding better metrics to evaluate the production performance of unconventional multi-fractured horizontal wells (MFHWs). This paper discusses the use of cumulative productionratio curves,normalized to a given reference volume in time (e.g. 12-month cumulative production) for different unconventional plays in North America to investigate the median trend for each play, and investigate the median ultimate recovery per play. The selection of using 12-month cumulative production as a reference volume as a normalization parameter is discussed. Historical production data from thousands of MFHWs in unconventional plays in the US (Bakken, Barnett, Eagleford, Fayeteville, Haynesville, Marcellus and Permian) and Canada (Duvernay, Montney and Horn River) was used to calculate normalized cumulative production curves for theprimary fluid, using different cumulative reference volumes at different points in time (e.g. 6, 12, 24, 36, 48 and 60 months). The observed trends for each of the selected plays werestudied using data analytics tools. A two-segment hyperbolic decline was used to match the median production trend to estimate the long-term performance of each play. Depending on the data variance, some plays exhibit more clear trends than others. By using normalized cumulative production curves, general profiles for each play were generated and compared. These Cumulative Production Ratio Profiles (CPRP) were extended using a two-segment hyperbolic equation to determine the Expected Ultimate Recovery Ratios (EURR) per play. Once a well in a region has been on production for a minimum duration equal to the reference time (e.g. 12 months), two results are readily determined: a) the EUR, and b) the production profile. The EUR is obtained simply by multiplying the appropriate EURR by the well's 12-month cumulative production; and the production profile is obtained by using the CPRP (cumulative production ratio profile) of the play and multiplying it by the 12-month cumulative production of the welland converting the results to daily rates. This cumulative plot serves as a normalized typewell for the region and can be used to guide the production forecasts of wells with a short production life.
Pei, Yanli (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin / Sim Tech LLC) | Sepehrnoori, Kamy (The University of Texas at Austin) | Gong, Yiwen (Sim Tech LLC / The Ohio State University) | Xie, Hongbin (Sim Tech LLC) | Wu, Kan (Texas A&M University)
The extensive depletion of the development target has triggered the demand for infill drilling in the upside target of multilayer unconventional reservoirs. To optimize the hydraulic fracturing design of newly drilled wells, we need to investigate the stress changes in the upside target induced by parent-well production. In this work, an integrated parent-child workflow is presented to model the spatial-temporal stress evolution and propose the optimal development strategy for the upside target using a data set from the Permian Basin. The stress dependence of matrix permeability and fracture conductivity is determined based on available experimental data and incorporated in our reservoir simulation with the aid of an embedded discrete fracture model (EDFM). With calibrated reservoir properties from history matching of an actual well in the development target (i.e., 3rd BS Sand), we run the finite element method (FEM) based geomechanics simulator to predict the 3D spatial-temporal evolution of the local principal stresses. A displacement discontinuity method (DDM) hydraulic fracture model is then applied to simulate the multi-cluster fracture propagation in the upside target (i.e., L2BSSh) with the updated heterogeneous stress field. Numerical results indicate that stress field redistribution associated with parent-well production not only occurs within the development target but also vertically propagates to the upside target. A smaller parent-child horizontal offset induces a severer deviation of child-fractures towards the parent wellbore, resulting in more substantial well interference and less desirable oil and gas production. The parent-child fracture overlapping ratio in our study is in 0.6 ~ 0.8 for the 400 ft horizontal offset and 0.2 ~ 0.5 for the 600 ft horizontal offset. Varying the parent-child vertical offset gives the same trend as we change the horizontal offset. But with a delayed infill time, placing child-well in different layers causes more significant variation in the ultimate recovery. Moreover, infill operations at an earlier time are less affected by parent-well depletion because of the more homogeneous stress state. The candidate locations to implement infill-wells are suggested in the end for different infill timing by co-simulation of the parent-child production. With the reservoir-geomechanics-fracture model, this work provides a general workflow to optimize the child-well completion in multilayer unconventional reservoirs. The conclusions drawn from this study are of guiding significance to the subsequent development in the Permian Basin.
Cuttings are an undervalued resource that contain vast amounts of relevant formation evaluation (FE) data in the form of entrained volatile chemistries from present day formation liquids/gases. Analysis of these chemistries in cuttings, or other materials (core, side wall core, and muds), enables decisions from well level completions to acreage/basin assessments on an operational timescale. This work compares analysis of rock volatiles to traditional FE (water saturation and permeability) data to demonstrate correlations to field studies in the Delaware Basin and the STACK. The field study from the SCOOP demonstrates how the analysis can be used to drive completion decisions; studies from the STACK demonstrate how the analysis drove acreage assessment and utilization decisions. All cases are presented from nonhermetically sealed samples showing the applicability of the analysis to fresh or legacy materials.
A unique cryo trap-mass spectrometry (CT-MS) system has been developed by Dr. Michael Smith enabling the gentle extraction of volatiles from cuttings, or other materials, and the subsequent identification and quantification of the extracted chemicals. All possible chemistries (hydrocarbons, organic acids, inorganic acids, noble gases, water, etc.) are extracted by gentle volatilization at room temperature under vacuum conditions and concentrated on a CT; the chemistries are separated by warming the CT and volatilizing as a function of sublimation point and then analyzed by MS. Advantages of this CT-MS over GC-MS are that chemicals that would not survive the conditions of a heated GC system can be analyzed and that the analysis does not require different columns as a function of the species type analyzed. The analysis works on both water and oil based mud systems. These results are combined with a geological interpretation to enable application.
The comparison field studies show that the analysis successfully reproduced Sw and permeability trends from petrophysics and sidewall core analysis. The SCOOP field study identifies the mechanism of underproduction in a Hoxbar well and a simple completion strategy for the lateral that would have significantly reduced costs while enabling equivalent production. The STACK field study was utilized by an operator to evaluate and understand the petroleum system across their acreage and enabled unique acreage utilization decisions in terms of well placement and lateral trajectory.
Enhanced oil recovery (EOR) potential in unconventional oil reservoirs looks promising but remains largely elusive because the industry is just beginning to realize that primary depletion may recover no more than 7-9% oil-in-place and there is no collective consensus on best EOR practices for tight oil. Moreover, vital scientific understanding of rock-fluid interactions in these formations is presently limited. The objective of this work was to experimentally demonstrate how rock-fluid interactions in nanofluid enhanced oil recovery (EOR) process can be probed at the nanoscale in a rapid and efficient manner.
In this study, atomic force microscopy, a high-resolution scanning tool, was used to characterize adhesion changes which directly relates to the surface energy released in process of wetting. Dispersions of 8-nm sized silicon dioxide nanoparticles were used as nanofluids. Freshly cleaved mica was to mimic shale-like mineral substrates while chips from Tuscaloosa marine shale were used as representative of composite rock surfaces. Methyl-terminated and carboxylic acid-terminated tips were used to represent non-polar and polar oil functional groups. Contact mode chemical force mapping was used for measurements of adhesion at the nanoscale. Each experimental run was completed for a 5 x 5 micron sample area for a duration of 30 min.
Force mapping results showed that adding nanoparticles to the liquid media reduced the adhesion force on the order of pN (10-12 N) to nN (10-9 N) due to reduction in non-electrostatic and electrostatic forces as well as adsorption of nanoparticles onto rock substrates. This finding is consistent with zeta potential measurements and SEM images which reveal that nanoparticles irreversibly adsorb onto phyllosilicate mineral surfaces and improve the wettability by rendering surfaces negatively charged and repelling oil molecules. These studies demonstrate that adhesion measurement can be used as an indicator of nanoscale wettability for rapid screening of different EOR processes in tight oil reservoirs. In addition, it encompasses surface chemistry, material science and core petroleum reservoir engineering for understanding fundamental rock-fluid interactions.
Chu, Hongyang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing / Texas A&M university) | Liao, Xinwei (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing) | Chen, Zhiming (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing) | Lee, W John (Texas A&M University)
Rate transient analysis (RTA) is an important method to predict productivity and reserves for reservoir and completion characterization in unconventional plays. In addition, multi-horizontal-well pads are a common development method for unconventionals. Close well spacing between multi-fractured horizontal wells (MFHWs) in multi-well pads results in significant interference from adjacent MFHWs. For RTA of production data from multi-horizontal-well pads, the influence of adjacent MFHWs cannot be ignored. In this work, we propose a semi-analytic RTA model for the multi-horizontal-well pad with arbitrary multiple MFHWs properties and starting production times. Combining Laplace transformation and finite difference analysis, we obtained a general solution of a multi-well mathematical model to use in RTA. Our model is applicable to cases of multiple MFHWs with different bottom hole pressures (BHP), varying hydraulic fracture properties, and different starting production times. In the solutions, we observe bilinear flow, linear flow, transition flow, and multi-MFHW flow. Rate normalized pressure (RNP) and its derivative are also affected by multi-MFHW flow. Two case studies revealed that the negative effect of interwell interference on the parent well productivity is closely related to the pressure distribution caused by the production of child wells.
RTA allows us to predict oil and gas well production rates and reserves to characterize formations and effectiveness of completions. (Lee and Wattenbarger 1997). RTA requires only production data (rate and pressure) and does not require long-term shut-in for pressure build up tests, and as such, most research has focused on RTA in unconventional applications (Lawal et al. 2013; Sahai et al. 2015; Yadav and Motealleh 2017; Ravikumar and Lee 2019; Baek et al. 2019; Yuan et al. 2019; Chu et al. 2019b). Development of unconventional resources relies on horizontal drilling and multi-stage fracturing (Chun et al.2020). Infill drilling is also common. Operating companies usually prefer to concentrate drilling rigs to core areas. For example,
The story of the US shale revolution is well known. Hydraulic fracturing techniques were executed by Mitchell Energy in vertical Barnett Play gas wells in the early 2000's, vertical wells matured into horizontal multi-stage frac wells, and one of the largest land leasing campaigns in history exploded as operators chased high gas prices.
As the natural gas market became saturated, the industry started to strip the natural gas liquids (NGLs) out of the gas stream to take advantage of the ever-rising oil pricing. When gas prices tumbled in 2011, and oil prices climbed north of $100/bbl, the industry looked to the liquid rich/oil plays, such as the Williston Basin, the DJ Basin, and the Permian Basin.
The turning point came in November 2014 when oil prices fell rapidly. As prices bottomed out at $22/bbl in February 2015, the industry saw a large exodus of operators and capital from the gas rich plays around the US to the liquid rich Permian. The Permian proved to be the haven for oil and gas development with its multiple pay zone targets, high EURs, low break-even costs, friendly regulatory environment, and access to markets. The rush for land, once again ensued, with the hope of an oil price rebound and promise of high returns to capital investors.
The rapid ramp up in activity from 2015–2018 did not come without challenges as it put strain on the availability of services and people, access to pipelines and markets, and access to frac sand/water. This drove up costs and resulted in mixed results for many companies. In addition, operators soon saw that with higher-than-expected gas and water production, expenses to manage these by-products sky-rocketed. Water handling and disposal became a huge portion of operating expenses and with gas export facilities at full capacity, companies started to flare gas in large volumes. Associated gas became a waste product, causing operators needed remove the gas and associated liquids from the revenue stream, and in some cases pay a high cost for flaring permits, rather than shutting in wells.
By 2019, a shift in the investment community was well underway. The days of growth-focused investment were coming to an end, and investors wanted to see returns on their investments. As prices still hovered around the $55/bbl range, investors were getting anxious to recover their capital invested in the industry, and throughout 2019 operators all talked about the ability to generate free cash flow. This paper analyses the free cash flow for three key unconventional basins across the US and discusses the associated economic impacts in each basin.