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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.
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.
Traditional geochemical techniques such as pyrolysis and Soxhlet extraction have been used for decades to guide conventional exploration. However, geochemical data obtained in the traditional way falls short of the demands of unconventional reservoir development. We have recently developed innovative analytical and data processing technology that allows geochemical information in the produced oil and rock samples to be captured at a much higher resolution (up to an order of magnitude) and fidelity. These unprecedented geochemical data reveal 1) static reservoir characteristics such as reservoir quality, oil saturation, and 2) dynamic reservoir performance characteristics such as frac growth, drainage height, and inter-well communication. These reservoir characteristics can have impacts throughout the lifecycle of unconventional reservoir development from well stacking & spacing, completion design, reservoir management, and EOR/IOR decisions.
Based on high-resolution/hi-fidelity geochemical fingerprint data, we have developed an integrated workflow to provide new reservoir characterization and production monitoring information that lead directly to enhanced development opportunities for unconventional reservoirs. By data mining the fingerprint data from the rock baseline, a group of Reservoir Characterization Indices (RCI) were developed, including reservoir quality index (RQI) and oil-in-place index (OIPI). Different from other rock-based core analysis, the RCI provided an independent dataset directly from the oil residing in the rock samples. They correlate well with petrophysical data and compliment landing decisions for lateral wells. Produced oil samples were collected from legacy and infill wells. Fingerprints based on over 2000 compounds, resolved from each produced oil sample, were used to reveal well communication through time, as well as quantitative vertical drainage variation against the vertical profile previously established using the core/cutting samples. Integrating the dynamic reservoir monitoring data with the static RCI data, geochemical fingerprinting technology helps operators identify key factors controlling unconventional well performance, such as well spacing, and significantly improves the operator’s ability to predict performance of future development strategies.
Key conclusions from the study include: 1) RCI generated in the workflow conformed well with independent petrophysical analysis; 2) Indications of similar zonal contribution in wells that were landing in different intervals; 3) Drainage geometries in all four landing zones appear to have distinct differences; 4) Distinct overlapped drainage geometries are also evident; 5) Parent wells experience changes in drainage geometry profile post-stimulation of offset child wells, then returned to their established geometry in a relatively short period of time.
Abstract In this case study, three sequential well pads were designed, stimulated and monitored to evaluate 1. Treatment order of stacked wells across multiple benches, 2. Completions optimization in proximity to a parent well and 3. The efficacy of treatment sequence in proximity to parent wells. Microseismic data were evaluated in conjunction with tracer and pressure data to provide a more detailed understanding of reservoir deformation and well connectivity using statistical approaches that consider the collective behavior of seismicity. High-resolution microseismic involves analyzing spatio-temporal trends in seismicity rather than reliance on microseismic event clouds to provide more meaningful assessment of hydraulically-linked seismicity vs. stress-driven seismicity. The findings of the first two case studies were applied to the stimulation of the third well pad to demonstrate the role of well sequencing in proximity to depleted zones and the impacts of completions design in managing well communication. Here we discuss the benefit of high-resolution microseismic in assessing perceived well interference by delineating the difference between hydraulically-linked and stress-driven seismicity recorded during multi-well hydraulic fracturing programs. In applying knowledge of reservoir deformation processes to customize stimulation programs, operators have additional tools to help manage reservoir stress, limit unwanted well communication and optimize production.
CNOOC, Several International Firms Sign Agreements for Areas Offshore China
China National Offshore Oil Corporation (CNOOC) has signed strategic cooperation agreements with nine international firms for two offshore areas in the Pearl River Mouth Basin off China.
State-owned CNOOC said the agreements—which include Chevron, ConocoPhillips, Equinor, Husky, KUFPEC, Roc Oil, Shell, SK Innovation, and Total—are a first step in establishing what could be long-term cooperation on exploration and development of offshore Areas A and B. Each international firm has existing upstream operations in China.
The 15,300-sq-km Area A lies in 80–120 m of water. Firms are open to explore its deep layers below the Paleogene Enping formation. The 48,700-sq-km Area B lies in 500–3,000 m of water. Firms can explore each layer beneath the surface of that area.
How Does Vaca Muerta Stack Up vs. US Shale? Data Tell the Tale
Matt Zborowski, Technology Writer
For what seems like forever, the upstream universe has awaited the emergence of Argentina’s Vaca Muerta Shale as the international answer to US shale.
In many regards, it already holds its own. In others, there is still much work to be done. Either way, 2018 and 2019 will mark a promising step forward for the play, according to data from research and consulting firm Rystad Energy.
US shale plays grew exponentially during their development phases, with the number of horizontal wells completed shooting up year-to-year in their first 5 years of relevancy. Vaca Muerta shows potential for a similar activity surge given geology “as good or better than the majority of the US plays,” noted Ryan Carbrey, Rystad senior vice president, shale research, during a recent Vaca Muerta-focused webinar.
Global Oil and Gas Exploration, Project Sanctions Expected to Rise in 2019
Matt Zborowski, Technology Writer
Global discovered oil and gas resources and big project sanctions are expected to remain on the upswing through next year, according to separate industry outlooks from Rystad Energy and Wood Mackenzie.
Internalizing lessons from a difficult last few years, operators are choosing investments more wisely and are now better prepared to deal with volatile oil markets, the consultancies concluded. “Oil and gas companies can cope with whatever is thrown at them in 2019,” said Tom Ellacott, Wood Mackenzie senior vice president. “Portfolios are set to weather low prices, and the recent slide in prices justifies the sector’s conservative mindset.”
Straight Out of OPEC, Qatar Flexes Global Ambitions
Trent Jacobs, JPT Digital Editor
Fresh on the heels of its announcement to leave OPEC, Qatar is positioning itself to become an increasingly active player in global energy projects through minority partnerships with big explorers. Its most recent acquisition involves a 35% stake in Italian operating company Eni’s interest offshore Mexico.
Late last year Qatar said that it would withdraw its 57-year membership in the Organization of Petroleum Exporting Countries and focus on increasing its natural gas production. Qatar is currently the world’s third-largest supplier of liquefied natural gas (LNG) behind Australia and the US.
ExxonMobil Makes 10th Discovery Off Guyana, Lifts Resource Estimate by Another Billion Barrels
Matt Zborowski, Technology Writer
ExxonMobil’s Pluma-1 well off Guyana encountered 37 m of high-quality hydrocarbon-bearing sandstone reservoir, marking the firm’s 10th discovery in South America’s newest oil powerhouse.
Located 27 km south of the Turbot-1 discovery on the southeast portion of the 26,800-sq-km Stabroek Block, Pluma-1 was drilled to 5,013 m in 1,018 m of water by the Noble Tom Madden drillship, which spudded the well 1 November.
The major now estimates that its discovered recoverable resources for the block total 5 billion BOE, up 1 billion BOE from its previous estimate made over the summer, around the time that it announced its eighth discovery, Longtail, also on the southeast part of the block. Its ninth discovery came via the Hammerhead-1 well to the west.
Mexico’s Giant Zama Discovery Gets New Interest Owner
Matt Zborowski, Technology Writer
Germany’s DEA Deutsche Erdoel AG has agreed to acquire privately held Sierra Oil & Gas, interest owner in six blocks in Mexico, including the giant Zama discovery.
Sierra holds a 40% nonoperated interest in the 465-sq-km Block 7 containing much of the shallow-water Zama discovery, where appraisal drilling is under way. Zama is estimated to hold 400–800 million BOE of recoverable resources with estimated peak output of 150,000 BOE/D. Production is expected to start up by 2022–2023. Talos Energy is operator and Premier Oil is the other partner.
Total Begins Production From Nigeria’s Giant Egina Field
Total advanced its global deepwater campaign 29 December with the launch of production from the Egina Field 150 km offshore Nigeria.
The Egina floating production, storage, and offloading vessel, which Total says is its largest ever, will be connected to 44 subsea wells and produce up to 200,000 B/D of oil. The field lies in 1600 m of water on Oil Mining Lease (OML) 130.
Total says the project was developed 10% under budget, resulting in savings of more than $1 billion, driven in large part by a 30% reduction in average drilling time per well. The French major’s operating costs in Nigeria have been slashed by 40% during the last 4 years, Arnaud Breuillac, Total president, exploration and production, said in a news release.
Oil Prices Take a 2014-Size Hit
Stephen Rassenfoss, JPT Emerging Technology Senior Editor
Oil prices fell sharply in late 2018, similar to 4 years ago, but this time around oil companies seem better able to make money at these price levels.
The US Energy Information Administration (EIA) made those observations in a new report released in December, after a day of trading in which the benchmark US price closed at $47.20/bbl. Brent closed at $56.49/bbl.
Companies that survived the price downturn that began in 2014 are in better shape now. “Most measures of profitability and balance sheet fitness indicate companies should be able to weather the recent price downturn,” the EIA report said.
Panja, Palash (Department of Chemical Engineering, and Energy & Geoscience Institute, University of Utah) | Velasco, Raul (Energy & Geoscience Institute, University of Utah) | Deo, Milind (Department of Chemical Engineering, University of Utah)
Abstract In this work, we estimate the Stimulated Original Oil In Place (SOOIP) of hydraulically fractured horizontal wells in prominent shale plays. This is done by compiling production data from hundreds of wells belonging to the Bakken, Niobrara, Wolfcamp, Eagle Ford, Bone Springs, and Woodford totaling over 2,500 wells. Additionally, we present probabilistic distributions of SOOIP with mean, standard deviation, P10, P50, and P90 estimates for each play. To circumvent the challenge of data availability for each well, we use the findings of a previous study where all reservoir unknowns are grouped into two major parameters. One of these parameters, alpha, is a function of the stimulated reservoir volume, compressibility, and pressure drawdown, where the last two are unknowns. While alpha is determined with high confidence for each well, we account for the uncertainty of compressibility and drawdown values across wells by assuming a normal distribution for these parameters. Lastly, by incorporating 1 million Monte Carlo samplings and a Mersenne Twister random number generator we estimate SOOIP distributions for each play with varying degrees of confidence. The final results show that the Niobrara and Bakken have the highest mean SOOIP values per well while the values for the Woodford and Bone Springs are the lowest among all six plays considered. Volumetric calculations using data from the literature qualitatively corroborate these findings. New insight on the stimulated volumes per well for prominent shale plays can be derived from these results as they correlate to horizontal well length, formation thickness, and hydraulic fracture half-lengths in each play.
Abstract The successful development of unconventional resources requires an integrated approach using multiple data sets to characterize and optimize recoveries. This study evaluates geological and completion drivers impacting well productivity within the Denver-Julesburg (DJ) Basin of eastern Colorado and southeastern Wyoming, focusing on the Core Wattenberg and Peripheral regions. Understanding these complex relationships is required to explain well performance variability across the play and optimize economics. Over 4,000 producing horizontal wells were analyzed across the study area. Completion data including lateral length, fluid intensity, proppant intensity, stage spacing and vertical well density were put though a comprehensive scrubbing process to identify and remove outliers. Oil and gas type curves were built for individual wells using RS Energy Group's proprietary software. Geological parameters for individual wells were derived from maps generated from over 2,000 digital wells logs, including TVD, hydrocarbon pore volume, isopach, geothermal gradient, clay volume and mud weight-derived pressure gradient, using bottomhole locations. Bayesian, boosted decision tree, linear and decision forest multivariable regression models were tested, and the model with the highest coefficient of determination was used. Permutation feature importance (PFI) method was used to rank variables by impact on recovery. The decision forest regression model was selected for the Core Wattenberg Niobrara and Core Wattenberg Codell sub-regions, whereas the boosted decision tree was chosen for the Peripheral DJ Niobrara and the linear regression model was selected for the Peripheral DJ Codell sub-region. Based on the selected models, fluid intensity and formation TVD were the highest-ranked variables across the entire basin. Introduction DJ Basin breakevens are competitive among North American plays, averaging $35/bbl WTI in 2017, behind the Midland and Delaware basin averages of $32/bbl and $33/bbl. Data analytics using a multidisciplinary approach offers both qualitative and quantitative techniques to characterize variables that influence well productivity. By integrating geological and completion data sets, regional trends are observed along with the key drivers that yield better recoveries. This analysis highlights optimal geological and completion parameters within the Niobrara and Codell formations that drive recoveries in both the Core Wattenberg and Peripheral DJ regions.
Abstract Multiple fracture placements in single wells have a sixty year history with first applications soon after hydraulic fracturing was patented. Fracturing technology has been applied to offshore deviated wells, sand control wells, tight gas, coal, chalks, shales and conglomerates in turn as "conventional" reservoir limits were reached and each "new unconventional" reservoir was encountered. As fracturing technology was adapted to make an "unconventional" reservoir into a conventional reservoir, the adaptations and evolutions needed became part of the technology tool box waiting for the next challenge. Each innovation improved and stretched the reach of completions and production engineering as new findings were incorporated to monitor, model, optimize and extend the ranges of fracturing use for high and low temperatures, high stress formations and a variety of other challenges. This review looks at the development of multi-fractured wells from its first application in vertical wells where one well could now do the task of three wells, to the first modern application of highly multi-fractured horizontal wells used in chalks, shales and tight oil and gas reservoirs. The technical focus is on the learning procession covering details of casing wear, cyclic pressure application, isolation mechanisms, perforation placement, well spacing and fracture spacing. The technical literature and field learnings have both been searched for applicable information with a surprising variety of engineering application details brought forth that are useful in optimizing a single well or a whole development.
SPE's recent Liquids-Rich Basins Conference rewarded attendees with far-reaching insight into how to economically exploit liquids-rich plays. Based on the theme "New Technology for Old Plays," SPE held the conference in Midland, Texas, from 11 to 12 September. The 29 speakers explored a wide range of topics and points of view from macro to detailed perspectives, centered on strategic thinking; current understanding of reservoir characteristics; proper application of completion, stimulation, and production techniques and tactics; and case histories. This is the third year the conference has been presented. Almost 300 attendees gathered at the Midland Convention Center to listen to four technical sessions--each with three speakers--each day; interact with four Knowledge-Sharing Poster speakers who presented during four half-hour breaks; hear a keynote speaker at Thursday's luncheon; and investigate the offerings of more than 20 exhibitors. Two training courses were also given--a 2-day course Monday and Tuesday, 9 and 10 September, titled "Modern Production Data Analysis for Unconventional Reservoirs"; and a 1-day course Friday, 13 September, titled "An Overview of Microseismic Imaging of Hydraulic Fracturing." The first session highlighted commercial and financial interests in oil resource plays and price pressures imposed by limited transportation in the areas of rapid development. Dave Pursell, managing director of Tudor Pickering Holt, kicked off the conference with his presentation, "US Crude Oil Production Growth and the Impact on Price Differentials… or Get Me off This Rock!" "'Liquids-rich' is my least favorite term," he said. Basically, he said further, what people are talking about is natural-gas liquids (NGLs): "If it's crude, they're going to say it." When considering the question of why Brent crude is at USD 110/bbl, he said, "Risk premium is the last possible answer before the shoulder shrug." He assured the audience that global crude fundamentals are fine, with crude inventories pointing to a balanced global market and global refined inventories below 10-year norms. The big story is taking place in the US. While US crude production has grown from around 7 million B/D in 2005 to around 9 million B/D in 2012, non-US, non-Organization of Petroleum Exporting Countries' (OPEC) crude production during the same period has remained fairly stagnant at around 44 million B/D. Organisation for Economic Cooperation and Development (OECD) countries' demand, which hovered at around 50 million B/D from 2000 to 2007, has tapered down to around 46 million B/D in 2012 and non-OECD demand has grown precipitously from less than 30 million B/D in 2000 to close to 45 million B/D in 2012. "When considering global growth," said Pursell, "it is really important to note that the only real growth in crude production is happening in the US."
SPE’s recent Liquids-Rich Basins Conference rewarded attendees with far-reaching insight into how to economically exploit liquids-rich plays. Based on the theme “New Technology for Old Plays,” SPE held the conference in Midland, Texas, from 11 to 12 September. The 29 speakers explored a wide range of topics and points of view from macro to detailed perspectives, centered on strategic thinking; current understanding of reservoir characteristics; proper application of completion, stimulation, and production techniques and tactics; and case histories.
This is the third year the conference has been presented. Almost 300 attendees gathered at the Midland Convention Center to listen to four technical sessions—each with three speakers—each day; interact with four Knowledge-Sharing Poster speakers who presented during four half-hour breaks; hear a keynote speaker at Thursday’s luncheon; and investigate the offerings of more than 20 exhibitors.
Two training courses were also given—a 2-day course Monday and Tuesday, 9 and 10 September, titled “Modern Production Data Analysis for Unconventional Reservoirs”; and a 1-day course Friday, 13 September, titled “An Overview of Microseismic Imaging of Hydraulic Fracturing.”
The first session highlighted commercial and financial interests in oil resource plays and price pressures imposed by limited transportation in the areas of rapid development.
Crude and Liquids Growth in the US. Dave Pursell, managing director of Tudor Pickering Holt, kicked off the conference with his presentation, “US Crude Oil Production Growth and the Impact on Price Differentials… or Get Me off This Rock!” “‘Liquids-rich’ is my least favorite term,” he said. “It’s as accurate as calling a dog a non-cat.”
Basically, he said further, what people are talking about is natural-gas liquids (NGLs): “If it’s crude, they’re going to say it.”
When considering the question of why Brent crude is at USD 110/bbl, he said, “Risk premium is the last possible answer before the shoulder shrug.” He assured the audience that global crude fundamentals are fine, with crude inventories pointing to a balanced global market and global refined inventories below 10-year norms.
The big story is taking place in the US. While US crude production has grown from around 7 million B/D in 2005 to around 9 million B/D in 2012, non-US, non-Organization of Petroleum Exporting Countries’ (OPEC) crude production during the same period has remained fairly stagnant at around 44 million B/D. Organisation for Economic Cooperation and Development (OECD) countries’ demand, which hovered at around 50 million B/D from 2000 to 2007, has tapered down to around 46 million B/D in 2012 and non-OECD demand has grown precipitously from less than 30 million B/D in 2000 to close to 45 million B/D in 2012.