With the industry shifting gears toward pad development there has been a significant increase in operator press releases to stockholders expressing concern about fracture driven interactions (formerly called "frac hits") within a drilling spacing unit (DSU) (
Depletion Mitigation Opportunities Depletion Mitigation Results Infill Well Asymmetric Frac in Toe Stage with Depleted Primary Well Overlap
Depletion Mitigation Opportunities
Depletion Mitigation Results
Infill Well Asymmetric Frac in Toe Stage with Depleted Primary Well Overlap
Historically, refrac operations in horizontal organic shale wells have had unpredictable production results, with the industry moving toward mechanical isolation following an often painful history that included single stage "pump and really pray" treatments with no diversion to "pump and pray" with chemical or ball sealer diversion. While results from mechanical isolation have been more consistent than these first two methods (
Africa (Sub-Sahara) United Hydrocarbon International finished drilling the Belanga North-1 exploration well located in Doba basin in southern Chad. The well was drilled to a total depth of 1392 m, and encountered three oil-bearing sand intervals--two in the targeted Upper Cretaceous "YO" sands and one in an untested shallower sand. United Hydrocarbon (100%) is the operator. Asia Pacific China National Offshore Oil Corporation discovered natural gas in the Qiongdongan basin, South China Sea. Well Lingshui 17-2--located in the east Lingshui sag portion of the basin at an average water depth of 1450 m--was drilled and completed to a depth of 3510 m. Lingshui 17-2 encountered a gas reservoir with a total thickness of approximately 55 m. Statoil Australia Theta has drilled and completed the Oz-Alpha 1 exploration well in the southern Georgina basin in the Northern Territory, Australia.
Findings from Kayrros suggest the average Permian well is both less productive and more expensive than reflected in public data. The projects are designed to reduce technical risks in enhanced oil recovery and expand application of EOR methods in conventional and unconventional reservoirs. Twelve organizations—universities and private technology companies—will conduct research and development on emerging shale plays and technologies covering everything from digital pressure-sensing to smart microchip proppant. The evolution of hydraulic fracturing is a long and circuitous one that deserves examination. Engineering and completions leaders from Liberty Oilfield Services did just that, authoring a paper that encapsulates the high points in the development of the groundbreaking completions practice.
The recent slump in oil prices has resulted in new terminology: “drilled uncompleted wells,” often referred to as DUC wells by the industry. In 2013 and 2014, when oil prices were more than USD 100/bbl, rate of return (ROR) from most unconventional plays was in the range of 15 to 50%, depending on the quality of rock and the operator’s portfolio in the basin. The objective of this paper is to address key challenges associated with DUC completions when they are eventually fractured and brought on line for production. The paper addresses four main concerns that can have significant impacts on productivity of DUC wells: fracture hits (well interference), reservoir quality (hydrocarbon drainage), multiple horizons (zone connectivity), and well spacing (high-density drilling). The paper also showcases case studies in which real-time observations made from wells have been used to validate predictions from forward-looking fracture and production models.
First, fracture hits commonly have been observed in all unconventional plays throughout the US, with effects on offset wells being mixed. Some fracture hits result in a positive uptick in production in offset wells, whereas other fracture hits affect production negatively in the form of increased water cut, reduced wellhead pressure, and other responses. Understanding fracture hits and their influence on other wells is very critical to avoid any detrimental impacts or to leverage positive effects on production. Second, reservoir quality decides how much oil in place is available for the DUC wells to drain, which, in turn, depends on length of production history and parent-well-completion geometries in offset wells. Third, in basins where there are multiple producing horizons or formations, fracture-height growth and interference between adjacent formations can result in asymmetric fracture propagation toward depleted zones. The longer these wells completed in the same/adjacent formations have been on production, the greater the extent of asymmetry will be. Addressing this concern requires a good understanding of drainage patterns from offset wells and evaluation of their impact on fracture geometries in DUC wells. Last, in areas with high-density drilling, a combination of longer production and fracturing stages with multiple perforation clusters per stage can leave very little oil available for the DUC well to produce.
Optimizing horizontal well placement is often not limited to identifying the most favorable reservoir, but also identifying the ideal target window within that reservoir. In unconventional reservoirs, the ideal target window must have both appropriate reservoir quality and the mechanical rock properties conducive to effective hydraulic fracturing. This paper presents two case studies from the Permian Basin. The first study directly compares wireline logs and core data with drilling vibration analysis. Analyzing drill bit vibrations, one can process mechanical rock property data. This process is called drill bit geomechanics. These high-resolution drill-bit-derived data were first calibrated to wireline and core data, then applied to target future landing zones. The second case study compares drill bit geomechanics data across three neighboring 10,000-ft horizontal wells, all of which landed in the same target zone. Based on the drill bit geomechanics data, the three wells showed notable differences in mechanical rock quality. The operator found the three wells’ production responses also differed.
High frequency measurements of drilling-induced vibrations were recorded through several producing Permian reservoirs. In the pilot well, the recording tool was run behind a coring assembly to obtain mechanical data at in-situ pressure and temperature. Elastic stress-strain relationships were used to solve for the stiffness coefficients and determine relative values of mechanical properties (i.e., Young's Modulus (YM) and Poisson's Ratio (PR)). The resulting mechanical data were compared directly to core analysis, wireline dipole sonic logs, and wireline image logs.
In general, the mechanical rock properties derived from drilling vibrations compared well with those from the sonic log and core analysis. One can attribute differences between the datasets to fluid effects and differences in resolution. The drill-bit-derived mechanical properties showed fine-scale changes and thinly-bedded intervals that were not identified by the sonic log. Using sonic measurements to determine in-situ mechanical properties can have non-uniqueness. Analyzing cores also includes challenges of translating exhumed core properties to those of in-situ conditions. Combining the in-situ measurement of mechanical properties from drilling vibrations with the traditional sonic log and core analysis minimized uncertainties. Increased understanding of mechanical properties in the pilot well informed the landing zone target intervals for the horizontal well development plan. Understanding mechanical properties is also critical to effective hydraulic fracture stimulation design and execution. Even within a landing zone, mechanical properties can vary laterally. Measuring and understanding these variations in mechanical properties can improve completions and lead to increased well productivity.
Gathering drill bit geomechanics data provides a lower cost and lower risk method to acquire mechanical rock properties in long, horizontal wellbores. These near-wellbore variations in mechanical rock properties are ideal for use in identifying target landing zones for horizontal wells. One can use the data to create high-resolution, laterally variable fracture simulation and reservoir models. By integrating these data sets with mechanical rock properties recorded while drilling, operators can have significantly higher confidence in choosing a target landing zone and improving completions.
After graduating from the US Naval Academy in Annapolis, Maryland, I spent 6 years in the US Navy and decided to move on when my obligation was over. After finishing my MBA, I began to look for a job. With an Annapolis degree, 6 years of management experience, and an MBA, I had numerous job offers from a wide variety of companies. In 1981, the oil and gas business was in full swing and many firms were hiring. The process of searching for and producing oil and gas was fascinating, and it called on a lot of the skill sets that I had acquired in my career.
Jaripatke, Omkar A. (Pioneer Natural Resources) | Barman, Indranil (Pioneer Natural Resources) | Ndungu, John G. (Pioneer Natural Resources) | Schein, Gary W. (Pioneer Natural Resources) | Flumerfelt, Raymond W. (Pioneer Natural Resources) | Burnett, Nikki (Pioneer Natural Resources) | Bello, Hector D. (Pioneer Natural Resources) | Barzola, Gervasio J. (Pioneer Natural Resources)
One of the most significant elements in the successful development of an unconventional multi-layered horizontal shale play, such as the Permian Basin Wolfcamp and Spraberry shales, is the continuous refinement of completion design programs in order to account for the specific geological characteristics of the target formation and spatial considerations. This paper examines a number of well completions, a large percentage of which are multi-stacked, over a four-year period in the Permian Basin. In this paper, we describe the ways in which a completion design program has been constantly refined in the development of Wolfcamp and Spraberry formations over certain areas of Midland Basin. Key performance drivers, such as regional pore pressure, rock properties and stresses, well spacing, etc. along with multidisciplinary data sets such as microseismic, tracers, bottom hole reservoir pressure, and production history are incorporated into modeling the completion designs. Details of the workflow, analysis of results and implementation of the Permian multi-stack design optimization plan are presented. The paper includes lessons learned from early vintages to modern completions, parent/child mitigation strategies, and future ideas to further optimize the operations. Information presented in this paper will help multi-disciplinary asset teams, consisting of engineers, geologists, analysts and managers; design a workflow for selecting appropriate design solutions for their individual shale assets.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk.
Artificial Lift Selection Strategy to Maximize Unconventional Oil and Gas Assets Value.