Completion Methods and Results Comparison of Devonian Shale in the Big Sandy Field

Friend, Michael L.; Keenan, Robert L.; Huck, Donald R.

doi:10.2118/30989-ms

Cited by 4 publications

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“…Perhaps more importantly, there is no control over the stimulation fluid and the resulting dimensions of the created fractures. In these low permeability formations, zonal isolation has been shown to be critical to multiple fractured horizontal well success [20][21][22] . In the Barnett Shale Formation, for example, pump down plugs [23][24] and external casing packers [25][26] have been utilized to improve isolation and improved fracture stimulations have been the result.…”

Section: Introductionmentioning

confidence: 99%

Horizontal Well Completion, Stimulation Optimization, and Risk Mitigation

Britt¹,

Smith

2009

All Days

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Horizontal wells have become the industry standard for unconventional and tight formation gas reservoirs. Because these reservoirs have poorer quality pay, it takes a good, well-planned completion and fracture stimulation(s) to make an economic well. Even in a sweet spot in the unconventional and tight gas reservoir, good completion and stimulation practices are required; otherwise, a marginal or uneconomic well will result. But what are good completion and stimulation practices in horizontal wells? What are the objectives of horizontal wells and how do we relate the completion and stimulation(s) to achieving these goals? How many completions/stimulations do we need for best well performance and/or economics? How do we maximize the value from horizontal wells? When should a horizontal well be drilled longitudinally or transverse? These are just a few questions to be addressed in the subsequent paragraphs. This paper focuses on some of the key elements of well completions and stimulation practices as they apply to horizontal wells. Optimization studies will be shown and used to highlight the importance of lateral length, number of fractures, interfracture distance, fracture half-length, and fracture conductivity. These results will be used to discuss the various completion choices such as cased and cemented, open hole with external casing packers, and open hole "pump and pray" techniques. This paper will also address key risks to horizontal wells and develop risk mitigation strategies so that project economics can be maximized. In addition, a field case study will be shown to illustrate the application of these design, optimization, and risk mitigation strategies for horizontal wells in tight and unconventional gas reservoirs. This work provides insight for the completion and stimulation design engineers by: 1. developing well performance and economic objectives for horizontal wells and highlighting the incremental benefits of various completion and stimulation strategies, 2. establishing well performance and economic based criteria for drilling longitudinal or transverse horizontal wells, 3. integrating the reservoir objectives and geomechanic limitations into a horizontal well completion and stimulation strategy, and 4. identifying horizontal well completion and stimulation risks and risk mitigation strategies for pre-horizontal well planning purposes.

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Section: Introductionmentioning

confidence: 99%

Horizontal Well Completion, Stimulation Optimization, and Risk Mitigation

Britt¹,

Smith

2009

All Days

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Spurring the Devonian: Methods of Fracturing the Lower Huron in Southern West Virginia and Eastern Kentucky

Rowan¹

2009

All Days

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The Lower Huron Shale can take claim as one of the earliest discovered sources of natural gas. As with all the shales though, extracting its reserves has been the challenge. To start, the physical properties of shale are not the same as typical sandstones, limestone, and siltstones that are targeted to produce natural gas. Along with this, the mechanisms for which the hydrocarbons are stored in place and transported are unique as well. Shale is notorious for having ultra-low permeability (µD) and because of this, the primary storage and transport of hydrocarbons comes through the series of natural fracture networks within the shale. Fracturing the shale then becomes a search for the natural fracture network that is holding the hydrocarbons. After drilling is completed, the question becomes exactly how do we fracture this well to achieve the best results? There are several ways to stimulate the wells that have been drilled in the Lower Huron. They range from straight nitrogen stimulation to varying quality foam stimulations. These two main methods of fracturing can then be broken down into many different style stimulations by changing rates, foam qualities, sand volumes and nitrogen volumes. A couple of things to look at when designing a stimulation job is depth, field of play, thickness of the zone, and its gamma ray reading on the log. This paper will discuss fracture styles and which ones seem to perform better in wells given certain characteristics and what might be changed to produce the best results. Introduction The Lower Huron Shale has been a mainstay in the Appalachian Basin in the production of natural gas since the early 1900's. With the history of producing the Lower Huron going back as far it does, it is evident that most fracturing techniques have been used to try and stimulate this zone. As technology advanced and the understanding of how natural gas was stored and transport to the wellbore increased, the practice of stimulating wells became more technical and controlled. These advancements came from natural production, shooting nitroglycerine, fracturing with different based frac fluids and foam fluids. All these practices have led the industry to where we are today in the processes and manners in which the Lower Huron is stimulated and what we consider best practices. Geology The Lower Huron Shale was formed in the Devonian approximately 350 million years ago. Part of the eastern half of the United States was covered by a shallow sea. Organic-rich material accumulated on the sea floor and was eventually covered. With the covering of the organics came high temperatures and pressures and this in turn helped produce the hydrocarbons. The hydrocarbons present are a direct correlation to the amount of organics that were laid down. These layers of organics fall in between layers of minerals producing what we call shale. The color of shale varies according to the amount of organics that were present in the formation. Typically the darker the shale the more organics that were present therefore the more gas that is in place. Natural gas is stored in rock pores, as absorbed gas, or in the natural fracture network with in the shale. Shale, unlike conventional reservoirs, presents the problem of having low matrix porosities and extremely low permeability. These two issues are what make shale classified as an unconventional reservoir. Conventional natural gas reservoirs rely on higher porosity and permeability to store and move the hydrocarbons from far a field to the wellbores to be produced.

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Comparing Production Responses from Devonian Shale and Berea Wells Stimulated with Nitrogen Foam and Proppant vs. Nitrogen-Only, Pike Co., Kentucky

MacDonald

Frantz

Merriam

et al. 2002

SPE Annual Technical Conference and Exhibition

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This paper presents results of a production data comparison and an economic analysis of two stimulation methods (nitrogen foam with proppant versus nitrogen only) pumped in more than 200 wells owned and operated by Equitable Production Company. The wells, located in Pike County, Kentucky, were completed in the Berea and Devonian shale formations, and each formation was stimulated separately. About half the wells were stimulated with nitrogen foam containing proppant; the other treatments consisted of nitrogen only. These wells were drilled in the 1990s and sufficient production data were available to make definitive comparisons. The results indicated that the wells treated with foam containing proppant significantly outperformed the wells treated with nitrogen only. Economic results also illustrated that it is more profitable to pump nitrogen foam with proppant even though the cost of the treatment is more than double. In furtherance of this study, the operator is currently pumping foam with proppant in wells within the study area and is identifying additional acreage for use of this stimulation treatment. Existing wells are also being evaluated for restimulation potential. The results of this paper are noteworthy for the Appalachian Basin because many operators pump multiple stages of nitrogen-only treatments. Introduction Major objectives of this study were to ascertain relative technical and economic benefits of completing wells with nitrogen foam containing proppant versus nitrogen without proppant in Devonian Shale and Berea wells within the project area. Additional objectives included evaluating reservoir quality, pay thickness permeability, and discovering the influence of these factors throughout the study area. The impact of these factors on stimulation effectiveness, production volumes, and estimated ultimate recoveries (EURs) was also determined. Fig. 1 shows the location of the study area in eastern Kentucky.

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Completion Methods and Results Comparison of Devonian Shale in the Big Sandy Field

Cited by 4 publications

References 0 publications

Horizontal Well Completion, Stimulation Optimization, and Risk Mitigation

Horizontal Well Completion, Stimulation Optimization, and Risk Mitigation

Spurring the Devonian: Methods of Fracturing the Lower Huron in Southern West Virginia and Eastern Kentucky

Comparing Production Responses from Devonian Shale and Berea Wells Stimulated with Nitrogen Foam and Proppant vs. Nitrogen-Only, Pike Co., Kentucky

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