In this paper we describe a novel method for water unloading of natural gas wells in mature reservoirs experiencing low reservoir pressures. Current methods for water unloading from gas wells have at least one of the drawbacks of restricting gas production, requiring external energy, using consumable surfactants, or being labor intensive. The proposed design offers a new approach to water unloading that does not restrict or interrupt gas production. It can operate without external energy, and uses no consumables. Virtual and physical simulators have been developed and the full-scale version of the concept has been studied in test wells to demonstrate the feasibility and performance of the new water-unloading concept. An industrial-grade preproduction prototype was tested successfully in a test gas well to validate this study.
He left behind a multifaceted legacy that testified to his entrepreneurship, philanthropy, and love of country. Within the oil and gas community, this legacy focused on his work to prove up the Barnett shale unconventional gas resource, which established him as the "Father of the Shale Gas Revolution." Through his vision, perseverance, and commitment, the knowledge base and application of existing and new technologies not only revolutionized the search for shale gas, but also carried over into tight oil and gas reservoirs, changing the global outlook for both. George Mitchell entered the oil and gas industry through the encouragement and tutelage of his older brother Johnny. After graduating from Texas A&M University in 1940, earning a degree in petroleum engineering with an emphasis in geology, Mitchell served in the Army Corps of Engineers during World War II. He began working with his brother on oil prospects while still a member of the Army Corps. He and Johnny established their first company, Oil Drilling Inc., in the late 1940s, with George generating drilling prospects and his brother finding investors. Ellison Miles, an acquaintance of George's from his time at A&M, started a drilling company in north Texas after leaving the Army. Source: Republic Energy, prepared by Emily Mitchell. Oil Drilling put together the necessary money and took their first lease in the Fort Worth basin, a 3,000-acre tract in southwest Wise County.
In the past few years, we have observed the introduction of smart technologies that adapt themselves to the specific needs of individual users. There are many mobile and web-based services with learning capabilities that play the role of a personal assistant in our daily life. The foundation of this new class of services is a paradigm shift from intensive computational modeling and simulation of complicated phenomena toward data driven analytics. The oil and gas industry with the uncertainties convoluted into our measurements and understanding of the subsurface should not be excluded from this recent paradigm shift. Data driven analytics have proven to be a powerful alternative to conventional numerical and analytical solutions. In their advanced form, data driven technologies may be used as comprehensive management tools of oil and gas assets.
In this paper, we study Hilight field in Powder River Basin, a mature field with large number of wells. Lack of sufficient dynamic data such as flowing pressure for mature fields is common among these types of fields. Conventional data analyses impose a challenge in the absence of time-variant field measurements in addition to production history. Acquisition of a comprehensive data set for oil and gas assets, in general, is a costly luxury that is not financially feasible for all investment budget ranges. Data-driven approach along with pattern recognition techniques can introduce a potential solution to this challenging task and extract practical and valuable insights which can be vital to identification, planning and developments of assets and plays.
In this work, data from nearly 400 wells has been analyzed. Data from completion and workover was partially available. Well logs for only 15 wells is accessible providing less than 10% petrophysical data attributes over the entire well sets. Available production rate history for 185 wells starts from June 1969 and extends until April 2012. The information value of this dataset is investigated through a multi-step workflow. The workflow includes reservoir delineation and geological modeling, volumetric reserve and recovery factor estimations, production decline curve analysis, fuzzy pattern recognition (FPR) analysis and key performance indicators (KPI) analysis. FPR analysis provides time-laps spatial patterns, enabling us to qualitatively study the reservoir depletion and fluid flow in Hilight field. The result of these analyses has been used to identify the depletion distribution over time and sweet spots for infill locations. KPI analysis identifies relative influence of different parameters on hydrocarbon production. Top-Down Model is developed and used for field development planning and economic analysis on proposed new wells. The workflow has a minimal computational footprint compared to conventional methods. It has been demonstrated how these data driven techniques can be employed as a guide toward an improved reservoir management and planning.
Intensified US exploration and production activity in the liquids-rich shale plays has tended to overshadow issues with base gas production, particularly the continuing struggle to remediate liquid loading and return pressure-depleted wells to production. In recent years, Devon Energy has intensified efforts to maximize base gas production through deliquification of its mature East Texas wells. Accordingly, the operator has realized tremendous success with artificial lift, which is generating an average 50% rate of return and effectively breathing new life into many of its old and struggling wellbores. More recently, Devon has focused its efforts on the use of Hydraulic Pumping Units (HPU), which have recorded an amazing track record in deliquifying and returning to production low-rate gas wells that no longer respond to plungers, soap or velocity strings.
This paper examines Devon's experience using HPU to deliquify East Texas wells in reservoirs that vary from very low bottomhole pressure with high permeability to higher pressure with very low permeability and everything in between. The targeted wells range in depth from 5,000 ft to 10,000 ft with wellbores between 2 7/8 to 7 in. diameters. All of these well types have been put on pump and responded very favorably.
The authors will review case histories from several divergent East Texas well types to illustrate the efficiency of pumping units in restoring production to these lower fluid rate wells. The discussion will focus on a newly engineered HPU, which comprises a vertical hydraulic cylinder on the wellhead to reciprocate the rods and pump and offers a number of HSE, operational and economic advantages over conventional pumping units. The specific features that make the HPU a very viable and often preferred alternative to conventional pumping units will be detailed, as will the growing pains and subsequent lessons learned in the East Texas deliquification campaign. Owing largely to the impressive results in the East Texas production-restoration program, HPU technology has since expanded throughout other US gas basins where liquid loading has become a predominate issue.
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, USA, 8-10 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. In recent years, Devon Energy has intensified efforts to maximize base gas production through deliquification of its mature East Texas wells. To that end, the operator has realized tremendous success with artificial lift, which is generating an average 50% rate of return and effectively breathing new life into many of its old and struggling wellbores.
The use of high density "mud cap?? tripping pills to provide adequate hydrostatic pressure downhole for well control is a common practice on managed pressure and underbalanced drilling operations. However, placing a high density tripping fluid on top of a lower density drilling fluid is an attempt to defy gravity, and too often the result is large volumes of the two fluids comingling, ruining the potential reuse of both. Viscosifying the tripping pill itself has been tried with some success, but problems encountered have included more difficult movement and storage of the tripping fluid, along with the risk of increasing the well's bottomhole pressure while pumping the large, viscous pill into place. A better solution to the comingling issue is to place a physical barrier between the two fluids to prevent their mixing.
A novel fluid with robust thixotropic properties was developed to serve this barrier fluid function. The shear thinning properties of this fluid allow for ease of placement in the wellbore prior to tripping, and when the high density "mud cap?? is displaced on top of the barrier fluid the comingling of the tripping fluid and the drilling fluid is prevented. After tripping the drillstring back to the top of the barrier pill, the pill can be washed through and disposed of at surface, leaving a clean drilling fluid in the wellbore. The development and initial use of this barrier fluid are the subjects of this paper.
An unconventional reservoir poses not only difficulties in producing it economically but also requires constrains about the well construction and tubular selection in order to keep the budget in acceptable limits. The tubular used for well construction and well completion must offer maximum integrity at, if possible, minimum costs for the life of the well. The costs associated with tubular are generated by the steel price plus the connection costs. Use of premium connections may not be justified in all unconventional reservoir applications, but as this study will prove, they offer better solutions when the life if the well is considered.
This paper starts with a review of main tight gas fields worldwide and based on the well analysis a general tendency for well completion will be shown. The second part of the work will focus in analyzing casing design criteria used in afore mentioned fields. As a result a comprehensive discussion about casing and coupling selection for unconventional wells will be generated. Premium versus non premium connections will be discussed and their impact on the life of the well will be analyzed.