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Occidental Petroleum (Oxy) said this week it has agreed to sell almost 25,000 net acres in the Permian Basin of Texas to Colgate Energy Partners III for nearly $508 million. Average output of the properties amounts to 10,000 BOE/D from about 360 wells in the southern Delaware Basin, Houston-based Oxy reported in its announcement. The sale, expected to close in the third quarter, will boost Midland-based Colgate's holdings in the Permian to about 83,000 acres with an estimated production of 55,000. Colgate said it plans to run up to six drilling rigs by year's end and boost average production to 75,000 BOE/D by 2022. Proceeds from the sale will be used to pay down Oxy's debt that was around $35.4 billion in March, down slightly from the $36.03-billion debt reported last June.
Don't look now, but the United States rig count has inched up in recent months, and the driver has been the old reliable of onshore oil production, the Permian Basin of west Texas and New Mexico. While some observers might see the scenario as a simple case of drillers responding to the recovery of oil prices over the spring and summer, the fact that rig growth occurred chiefly in the Permian indicates there is more to the story. And along with a similar, smaller shift of gas rig activity toward the Marcellus and Utica basins in Pennsylvania and Ohio, the statistics suggest what the geographic footprint of an eventual, long-term recovery may look like in the US. The number of active oil rigs nationwide rose to 407 for the week ending on 2 September, according to Baker Hughes, up from 316 for the week of 27 May. Of the additional 91 rigs, 65 were activated in the Permian Basin.
Sorkhabi, Rasoul (Energy & Geoscience Institute, University of Utah, Salt Lake City, Utah) | Panja, Palash (Energy & Geoscience Institute, University of Utah, Salt Lake City, Utah Department of Chemical Engineering, University of Utah, Salt Lake City, Utah)
The Wolfcamp and Bone Spring formations of Lower Permian age in the Permian superbasin of west Texas and southeast New Mexico have contributed greatly to the US shale oil revolution in the recent decade. These formations were deposited in a rapidly subsiding basin at the southern margin of the North America craton during collisional tectonics in Late Paleozoic times. Here we analyze production data from nearly 4,800 horizontal wells drilled into Welfcamp and Bone Spring to constrain petroleum accumulations. The data indicate a bimodal distribution of oil and gas occurrence in Wolfcamp suggesting the migration of oil and gas from deeper (∼11,000 ft.) to shallower levels (4,000-6,000 ft.) in the same formation. Oil accumulation in Bone Spring is concentrated at the depths of 11,000-7,000 ft. with some intervals being more productive mimicking the alternating position of shaley and sandy layers in this formation. High gas-to-oil ratios are found at shallower levels for both formations. This study offers an application of reverse engineering to petroleum system analysis and supports the concept of intra-formational migration in the tight (shale) oil formations.
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.
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.
Tittlemier, Troy (Trey Resources) | Speight, John (Trey Resources) | Hager, Charles (Trey Resources) | Chiniwala, Barzin (Geolog Surface Logging) | Martocchia, Alberto (Geolog Surface Logging) | Easow, Isaac (Geolog Surface Logging)
Abstract The Southern Delaware basin has proven to be prolific for production of liquid rich hydrocarbons with operators targeting in the various layers of the Permian and deeper Paleozoic formations. With deeper formations, the thermal maturity of the source rocks increase and the reservoir fluid expected is predominantly Gas. There have been indications of potential liquid rich production in specific geological, structural and thermal maturity settings, but data points are limited and not many laterals have been drilled, and completed yet. Recent log and core evaluations have shown presence of natural micro and large aperture fractures in the Permian and other formations in the basin. These fractures can potentially enhance production and sometimes cause challenges to the drilling process. Operators can utilize superior technology from advanced surface logging to characterize many important aspects of formation evaluation which can be performed while drilling. Cost-effective technologies utilized in this study include advanced mud gas geochemistry, fracture detection from mud flow, chemostratigraphy and source rock evaluation. These data were then combined with open-hole wireline logs to determine the best approach to identify targets and plans for completions. This paper will demonstrate how an integrated approach to reservoir characterization was utilized by an operator in the Southern Delaware basin to evaluate their prospect in a vertical pilot and 2 laterals targeting the Paleozoic formations. The operator selected the best points for landing depths in both the Wolfcamp and Woodford by integrating an evaluation of the reservoir quality, production potential, reservoir compartmentalization, source rock character, micro-fractures (compared to interpreted FMI log), an estimation of reservoir fluid type and predicting GOR. These techniques were used to aid geo-steering the laterals and provide more inputs for rock typing. This integrated approach is a non-intrusive and cost-effective alternative for reliable formation evaluations. These insights can aid operators to map regional hydrocarbon distribution, locate fracture prone reservoirs, predict porosity permeability related to fractures, identify faults, estimate GOR or CGR, identify higher water production intervals, and plan future drilling and completions strategies. These deliverables are applicable for targeting primary and secondary targets within the greater Permian basin.
Abstract Optimum subsurface well spacing is a key parameter impacting production of unconventional reservoirs in a multiwell pad development. Instead of focusing on hydraulic fracture half-length of a single well, we evaluated subsurface well spacing with multiple wells at the section level to consider well interactions and reservoir property variations. Well distance can be determined beyond which the incremental recovery and economic benefit begins to erode due to the extra well costs and/or well interference. From a field application perspective, this paper presented our systematic study on subsurface well spacing in the Permian Basin for unconventional reservoirs which consisted of three main components, i.e., modeling, data analytics from existing field pilots, and economic evaluation. Two 3D earth models were built as representative areas for the Midland and Delaware basins. The target formations include Wolfcamp and Avalon respectively. To capture upsized and downsized completions, a wide range of fracture designs in combination with different subsurface well spacing scenarios were conducted for both hydraulic fracture modeling and reservoir simulation. A complex fracture network was generated by introducing natural fractures and considering hydraulic fracture propagation and branching. For each combination of fracture design and well spacing, well interference was determined by estimating ultimate recovery (EUR) difference between a single well and a middle well from multiple wells. Benefiting from active unconventional shale developments in the Permian Basin, we further carefully analyzed field pilots that were executed recently while having relatively long production history. At the section level, economics was done to evaluate capital efficiency of various scenarios. Results from both modeling work and pilots in two different basins aligned well, indicating that at the section level larger hydraulic fracture size without an increase in subsurface well spacing does not necessarily improve section EUR and there is a point of diminishing returns. Larger subsurface well spacing with bigger fracture size is thereby a preferable combination.
Due to advances in recording capabilities, seismic data for land oil-industry surveys is now often recorded continuously. A large portion of these data is usually discarded since it is not directly used for conventional imaging purposes. However, there is a growing consensus that these "surplus" recordings contain a variety of useful information about the subsurface, especially for academic seismologists but also for oil explorers. This paper presents an example of extraction of 3D information about the deep crust from such recordings. In this case the deep information was retrieved from a post-harvest but pre-correlation dataset by means of extended correlation. Although signal penetration in this particular area is limited by an extremely thick (>20,000 ft) overlying sedimentary cover, the exercise demonstrates the tremendous potential of systematically mining the rapidly expanding database of continuously recorded oil exploration data, and the clear need to preserve rather than discard the unconventional portions of those records.
This paper reports a pilot study of a large N (number of recording channels), vibroseis dataset acquired in southeast New Mexico in 2014 and provided to Cornell's Department of Earth and Atmospheric by Fairfield Nodal. The dataset consists of uncorrelated records harvested for a conventional reflection survey, cut into 21 second shot gathers for conventional correlation with a 16 second, 4-76 Hz upsweep. Although ideally our analysis would have been carried out on data harvested specifically to allow full correlation to the crustal depths of interest, this shorter conventional harvest was more quickly available at this point, and serves to illustrate that even these conventional harvests can be productively used. The additional correlated data lengths were obtained by the technique of extended correlation (Okaya, 1986) in which bandwidth is sacrificed for greater correlated record length.
Geology and seismic survey
The seismic data presented here were acquired by Fairfield Nodal Acquisition and Processing Company in South East New Mexico (Figure 1) and was provided to Cornell University specifically to demonstrate extraction of deep reflectivity. The harvested length of data is 21 second, which when correlated with the 16 second upsweep of 4-76 Hz, yields a conventional correlated record length of 5 seconds. This travel time corresponds to approximately 15 km depth for relevant velocities.
Abstract Maximizing ultimate recovery in unconventional wells presents many completion challenges. Among the most relevant, is consistently initiating multiple dominant fractures in close proximity to each other along the lateral. The most common fracturing method, Plug-and-Perf (PnP), relies on stimulating multiple clusters at once, leaving much of the pay zone unstimulated due to fractures initiating at the path of least resistance instead. These unstimulated sections create gaps in the fracture networks, which result in lower well profitability by hindering production and reducing estimate ultimate recovery (EUR). An alternative completion system, coiled tubing-activated frac sleeves (CTFS), is a method that provides accurate fracture placement and greater efficiency. This paper evaluates the production performance of this single-entry fracturing technique compared to the traditional multi-entry PnP method in the Granite Wash and Bone Spring formations. In this study, production analysis was done to compare performance CTFS vs PnP wells. Monthly well production data was derived from public sources. Decline curve analysis was used to appraise the estimated ultimate reserves for each well compared to the other wells in the immediate surrounding area. To complement the decline curve analysis study, a single stage reservoir simulation study is also included in order to compare the performance of the two completion methods. Three and six clusters for PnP stage and 3 entries for the single-entry completion were first simulated in hydraulic fracturing software. The estimated fracture geometry and conductivities were then used to generate a single stage reservoir simulation model. The properties of the reservoir were based on Wolfcamp formation. The simulation estimated cumulated recovery in 30 years. The results of the study show that the use of the single-entry fracturing technique has improved production in comparison to offset wells that were completed conventionally. In the Bone Spring formation, a well completed with CTFS outperformed top 20% producers in the same formation. In addition, results from fracture modelling and reservoir simulation show that more efficient and evenly distributed fracture networks were achieved by using the single-entry technique. Consequently, production has improved by 12% over the multi-entry technique. Also, long-term performance analysis of the Granite Wash study confirms that the use of CTFS as an alternative to PnP has tripled the estimate ultimate recovery. Hence, the CTFS method improved overall fracture placement and proved to be a more efficient alternative to PnP method. The paper presents novel information by evaluating long-term production data and benefits of single-entry stimulations compared to multiple entry fracturing treatments. Additionally, analysis of actual field data through the use of fracture modeling, reservoir simulation and type well analysis provides new technical insights when comparing fracture geometry, hydrocarbon recovery, and production performance between single and multiple-entry wells.
A 3,680 foot (1122 m) vertical Permian Basin well was evaluated using an integrated, multi-instrument dataset acquired while drilling to identify zones of interest for lateral targets. A total of 161 cuttings samples were analyzed to determine the mineralogical (X-Ray Diffraction; XRD), organic (programmed pyrolysis via Source Rock Analyzer), and elemental (Energy Dispersive X-Ray Fluorescence spectroscopy; ED-XRF) composition while gas in air and gas in mud samples were analyzed every foot using a quadrapole mass spectrometer and a Thermal Conductivity Detector (TCD; GC-TRACER™) respectively. Each zone identified as a potential reservoir target exhibits TOC values above 2 wt%, Total Gas (THC %) 3 to 5 times greater than the background gas, Tmax and methane content (C1%) or C1/THC values suggesting that the reservoir has reached thermal maturity for mixed type II/III kerogen type determined from Hydrogen and Oxygen Index ratios, and S1 values above 1 mg/g considered adequate for unconventional reservoir production. The zones are further evaluated based on their mechanical properties including bulk mineralogy, calculated Brittleness Index, fluid properties, C1/ROP, and Helium concentration then ranked based on the likelihood of brittle behavior and fractures present during reservoir stimulation. Additionally, conditions most favorable for extensive organic matter preservation during the time of deposition were assessed using elemental proxies such as V, Ni, Mo, and U and were evaluated to further rank each zone by statistical correlation to organic and gas values (regression; R2). Of the three zones of interest identified, Zone C spanning 650 feet of the lower Pippin, lower Wolfcamp, Cisco and Cline and specifically one narrow target Organic Zone 8 within Zone C was determined to exhibit the best mechanical, geochemical, gas saturation , and elemental characteristics among all lateral targets in the wellbore. This technique of combining sophisticated cuttings analysis with advanced gas-in-mud detection systems deployed at wellsite allowed the operator to make more informed drilling decisions by not only identifying zones of interest but also the ability to rank each zone based on the most favorable mineralogy, mechanical properties, hydrocarbon content and quality, fluid type and maturity, relative permeability, relative water saturation, and paleoredox and organic matter proxies most associated with greatest potential. Additionally, these technologies and techniques can also be employed to determine wellbore position during the build and also characterize the reservoir in the horizontal to better inform completions decisions.