The challenges of producing and lifting unconventional oil and gas economically is no doubt the most daunting phase of unconventional oil and gas development. The traditional approach of lift selection is no longer sufficient to effectively manage unconventional wells, with high decline rates between 40 to 80% in the first year. Slug flow, high free gas production, solid (proppant, scale, paraffin), horizontal wellbore geometry, surface pad for multi-well in a cellar, and other unique unconventional wells problems are continuously testing the limit of our existing artificial lift systems. As it might be expected, this is invariably, affecting the economic viability of unconventional oil and gas production. This paper presents an exceptional Artificial Lift selection process, required to maximize unconventional oil and gas asset value. The presentation includes a case study of Permian Delaware basin unconventional formations. The lift evaluation process which includes, a combination of several output from various models (reservoir, well and economic models) developed to analyze the economic impact of various artificial lift selection on the well-life is also presented. Three distinct periods are defined for the analysis: Managed Flow-Back Managed Production (Managed Drawdown) End of Life The overarching impact of lift selection and application, on Lease Operating Expense (LOE), Net Present Value of Cash Flow, Overall Asset Value Rate of Return on Investment and other Economic Indicators, for oil and gas operators is highlighted in this paper. Artificial Lift Types were evaluated based on several criteria through elimination and selection techniques. Artificial Lift is phased over the life of the well according to current and expected production rate requirement and lift method capability. Other major consideration includes flexible rate delivery, solid handling, and failure frequency - repair cost and operational expense and initial lift cost and required infrastructure. The output from the type of curve/production forecast, combined with well performance modeling was used to determine future well and reservoir performance. Formation was grouped into various categories based on reservoir characteristics and fluid properties The results showed cases of lift type selection for various types of unconventional formation. Actual well performance and lease performance results are also presented. The managed production (drawdown) period has a major deciding factor on the artificial lift selection strategy. Combination of traditional artificial lift selection processes with several other model output to create artificial lift selection strategy for Permian Delaware basin unconventional formation is applicable in other unconventional basins
The Natural Gas industry is often faced with the challenge of selecting an optimal Artificial Lift method for a well in the midst of various artificial lift type choices. These challenges become more complex with increasing dynamic changes in well characteristics over the life of a well. This paper presents a case study on artificial lift selection strategy for unloading liquid from gas well in San Juan basin located in Southwestern, Colorado, and Northwestern, New Mexico. Various modeling techniques were applied to evaluate the lowest bottom hole flowing pressure for various Artificial Lift system types and wellbore geometry. Real life data acquired at the field trials was used to validate model results. The selection strategy resulted in the creation of a robust artificial lift selection matrix and charts for various well configurations as well as production rates for optimum well performance. This approach has a significant impact on gas well production; often loaded up with liquid and prematurely abandoned, due to lack of proper artificial lift strategy. The paper may assist the gas well operator and the need to adequately design, install and operate an optimum artificial lift system for the life of the gas well. Introduction A gas well with high reservoir pressure and a high gas production rate carries liquid from bottom hole to the surface as a fine mist of droplets, with the droplets traveling close to the speed of the gas. The liquid can be oil, condensate and/or water. Any combination and percentage composition of these liquid types may be produced in association with gas. As reservoir pressure depletes production, production rate falls - the gas flow velocity reduces and drops below a critical velocity required for gas to move liquid droplets up to the surface (References [1],[2],[7]&[8]). Liquid then begins to accumulate at bottom hole and near the well bore region. The gas well loses its capability to lift liquid from bottomhole to the surface. This phenomenon is known as "Liquid Loading". The accumulated liquid increases bottom hole flowing pressure due to an increase in liquid holdup in the tubing and a height of liquid build-up in the wellbore. The relative permeability of gas and gas mobility in the near well bore region may also be impaired as a result of increased water saturation. Thus, it acts like "skin" damage to the reservoir known as "Liquid Block". If no intervention work is performed to remove liquid from the sandface and the well will eventually cease will flow at a lower rate and many eventually cease to produce due to loading, There are many artificial lift techniques available to be used to attempt to continously remove liquids from a liquid loaded gas well. See Table 1 and Table 2 below, which is a basic chart of current artificial lift and unloading methods for gas well. This table could also include velocity strings, intermitting the well, and other novelity pumps but the basic methods of artificial lift for dewatering gas wells are included. Several articles, papers and textbooks, (See References [1] to [21]) do provide detailed information on various methods of unloading a gas well. In general, these methods is categorize into two main groups. These groups are based on source energy used to provide the required lift. The two groups are the Reservoir Supplied Energy Systems and the External Supplied Energy Systems.The Reservoir Supplied Energy Systems include methods such as:Well Cycling On and Off (Timer/Stop clocking)Venting and Pit Blow-downs (environmentally unacceptable option)Surfactant (Foamer)Velocity StringWell SwabingPlunger
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA common characteristic of "challenging" unconventional gas resources, namely low permeability sands, shale and coal bed methane, is that the ultimate recovery is dependent on economic removal of liquids accumulation, generally termed "deliquification". This resource is making up an everincreasing part of the North American gas supply. Since there is no one "perfect solution", and the problem affects thousands of wells, the opportunity involves not only technology development but also knowledge management and building resource capability. This paper outlines the scope of impact and opportunity in North America, followed by the industry's approach and progress in the arena. The North American industry is working a variety of deliquification technologies for "challenging" gas, with developments ranging from adapting existing oil-field technologies, to developing gas-specific technologies, to "on the horizon" technologies. Examples in each stage of the development process will be shown.The effective communication of these developments to operators and suppliers is also a necessary component. The industry-wide annual conferences that have emerged in the last seven years are the primary avenue for this communication, and are supplemented in some cases by operator internal networks.This combination of technology development and effective communication is increasingly allowing North American operators to maximize the recovery of challenging gas resources.
Plunger lift technology has been applied systematically and successfully to unload liquids from marginal tight gas and coalbed methane wells in San Juan North Basin. This article presents the recommended practices, case studies, and results of excellent plunger lift application and optimization. A production increment of over 4 MMcfd has been achieved and sustained on about 40 plunger lift installations. Most wells that were chosen for plunger installations were either on a plug and abandon (P&A) list or on temporary abandon (TA) status. Neither gas production nor anticipated production uplift from wells could justify installation of a more costly artificial lift system such as sucker-rod pump to de-water wells. Amazingly, production uplift of more than 200 Mcfd, and/or production increment of over 300%, was realized on some wells. It important to note that many operations use the practice of surfacing plungers by auto-venting, thereby releasing greenhouse gas (GHG) into the atmosphere. Plungers were operated successfully in San Juan North operations without this practice. All these results were achieved through applications of new plunger lift technology, efficient plunger type selection, monthly and quarterly reviews, proper maintenance, optimization and monitoring, i.e. effective utilization of plunger lift data. The strong alliance that was formed with the plunger equipment provider was one of the important inputs to our plunger lift journey. This new approach is a significant departure from the conventional ways of operating plungers, whereby service companies traditionally supply plunger hardware to the producing companies to operate with little "service" involved. Also, the field operations' teams, with their perseverance, offered a very important contribution to this successful venture. Introduction Gas wells, as a result of depleting reservoir pressure, show a decrease in production over time. The liquids that are associated with the produced gas tend to accumulate in the gas well. The associated liquids could be water, oils or condensates. This liquid loading heightens and futher reduces the gas flow rate. Turner et al.1 and Coleman et al.2 models, give the minimum gas flow rates required to lift the entrained liquid droplets at certain wellhead pressure. There are a host of artificial lift methods3 available to de-liquefy gas wells, one such method being plunger lift. Given the consideration of low rates, economic feasability, well characteristics and mechanical integrity, plunger lift became the obvious choice. Plunger lift is an intermittent form of artificial lift which utilizes the natural energy of the reservoir to lift the liquids out of the wellbore. The feasibility and consideration of plunger lifts are discussed in the literature4–9. This article brings to light success stories of wells with low flow rates that were not producing to their full potential and would at times have to be shut in to build up pressure. The operator and plunger provider tie-up coupled with vital input from the field helped establish a setup wherein regular monitoring and field input resulted in a production increment of over 4 MMcfd for about 40 wells. The wells were chosen on the basis of their plunger viability, and plunger selection was made based upon sealing, depth of down-hole stop, bottomhole pressures, line pressure, annular communication, sand and paraffin production, etc. The availablity of the SCADA system allowed dynamic monitoring of changes and their effect on the wells. In addition to conventional plunger lift, multi-stage plunger lift technology was used, and plunger enhanced chamber lift (PECLTM) 10 is being considered for the future. Details are provided in the following sub-sections. Geology San Juan Basin, which runs along northwestern New Mexico and southwestern Colorado (Fig. A-1), is one of the most prolific natural gas producing regions in North America. The three major reservoirs, namely upper cretaceous Dakota, Mesa Verde group and Pictured Cliffs sandstone (Fig. A-2), have produced 22 Tcf of gas as of 2004 according to Fassett et al11. The Basin and Blanco Fruitland coal, which overlies the Pictured Cliffs sand (Fig. A-2), conformably holds a resource base on the order of 50 Tcf of coal bed methane (CBM) as per Kelso et al12.
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