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Abstract A recent series of tight gas discoveries in the Amin format ion of the greater Fahud area represents some of the most exciting exploration success of this decade in the Sultanate of Oman. The structures have been evaluated as containing very significant amounts of gas locked in a challenging deep and hot environment requiring hydraulic fracture stimulation. Recently, horizontal well trials started taking place in two of the structures aiming for testing efficiency of this type of completion and further evaluation of formation deliverability. Successful completion of horizontal laterals would open new horizons in this challenging environment. Achieving this goal is not possible without thorough evaluation of reservoir conditions followed by completion and stimulation. Horizontal well performance in a tight gas reservoir is largely controlled by the number of hydraulic fractures placed along the lateral and their spacing and conductivity. Designing a reservoir access strategy might not be a trivial task, either, when the well trajectory intersects several productive vertical layers and the reservoir properties are changing laterally. Manual selection of intervals and perforations could be susceptible to mistakes and may be perceived as subjective at times, while also being time and effort consuming. The workflow based on reservoir quality (RQ) and completion quality (CQ) developed in North America for unconventional resources for optimizing completion decisions brings engineering to this process for stage and cluster selection in horizontal sections. This project applies the same reservoir-centric RQ/CQ workflow integrating all available data and creating specific criteria and cutoffs applicable to a specific tight gas field in the Sultanate of Oman.
Abstract Total E&P is currently operating a tight gas field in Argentina, consisting of a low permeability and heterogeneous sandstone under hydrostatic pressure regime. The field is mainly developed with casing-cemented horizontal multi-frac wells at 1700 m TVD and 3000 m MD and vertical wells targeting the same depth. Numerous technical drawbacks were faced at the beginning of field development, threatening the chances of producing commercial rates and eventually locking a projected campaign. As a result, innovative solutions in terms of stimulation and reservoir evaluation techniques had to be deployed in order to achieve sustained productivity. After performing more than 200 fracture treatments in 10 multi-frac horizontals plus 50 vertical wells, several key lessons were capitalized in the field of; Fracture design, including proppant selection and the application of ultra light weight proppants A new approach in permeability assessment allowing completion optimization of horizontal wells Horizontal drain vertical placement in a thick reservoir One relevant step in the process was, in addition, learning to manage reservoir free water production by introducing the appropriate artificial lift techniques. This paper summarizes the main challenges, milestones and lessons captured in the completion and productivity domain that finally enabled a cost effective field development.
To evaluate a layered, tight gas reservoir and design the well completion, the operator must use both a reservoir model and a hydraulic fracture propagation model. The data required to run both models are similar and can be divided into two groups. One group consists of data that can be "controlled." The second group reflects data that must be measured or estimated but cannot be controlled. The data required to run a reservoir model depends on the type of model one chooses to use.
Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction Tight gas is the term commonly used to refer to low-permeability reservoirs that produce mainly dry natural gas. Many of the low-permeability reservoirs developed in the past are sandstone, but significant quantities of gas also are produced from low-permeability carbonates, shales, and coal seams. In this paper, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight-carbonate and gas-shale reservoirs. In general, a vertical well drilled and completed in a tight gas reservoir must be successfully stimulated to produce at commercial gas-flow rates and produce commercial gas volumes. Normally, a large hydraulic-fracture treatment is required to produce gas economically. In some naturally fractured tight gas reservoirs, horizontal wells can be drilled, but these wells also need to be stimulated. To optimize development of a tight gas reservoir, a team of geoscientists and engineers must optimize the number and locations of wells to be drilled, as well as the drilling and completion procedures for each well. Often, more data and more engineering manpower are required to understand and develop tight gas reservoirs than are required for higher-permeability conventional reservoirs. On an individual-well basis, a well in a tight gas reservoir will produce less gas over a longer period of time than one expects from a well completed in a higher-permeability conventional reservoir. As such, many more wells (closer well spacing) must be drilled in a tight gas reservoir to recover a large percentage of the original gas in place compared with a conventional reservoir. Definition of Tight Gas Reservoir In the 1970s, the U.S. government decided that the definition of a tight gas reservoir is one in which the expected value of permeability to gas flow would be less than 0.1 md. This definition was a political definition that has been used to determine which wells would receive federal and/or state tax credits for producing gas from tight reservoirs. Actually, the definition of a tight gas reservoir is a function of many physical and economic factors. The physical factors are related by Darcy's law, as shown in the stabilized, radial-flow equation, Eq. 1, (Lee 1982).
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170852, “Development of a Stranded Tight Gas Field in the UK Southern North Sea With Hydraulic Fracturing Within a Subsea Horizontal Well: A Case Study,” by Marc Langford, SPE, Douglas Westera, SPE, and Brian Holland, SPE, Centrica Energy, and Bogdan Bocaneala, SPE, and Mark Norris, SPE, Schlumberger, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed.
There are more than 100 accumulations in the southern North Sea that are flagged as stranded fields. One of these stranded tight gas fields, the Kew field, has been developed successfully with the use of a subsea well, horizontal drilling, and hydraulic fracturing. Because this was a subsea development well, all the hydraulic-fracturing operations had to be performed with the rig in place. The utmost efficiency of the operations was paramount; otherwise, the economics of the project would be affected negatively.
The Kew field is a gas field, with small volumes of associated condensate, located in Blocks 49/4a, 49/5a, 49/5b, and 49/4c of the UK continental shelf. It lies 120 km east of the English coast and 5 km west of the UK/Netherlands median line. The field location is pictured in Fig. 1. (For further geological and geophysical details of the Kew field, please see the complete paper.)
The planned Kew 49/04c-7Y subhorizontal development well was drilled along the crest of the Kew structure and is a sidetrack of the existing (suspended) Kew appraisal well 49/4c-7z.
The planned sidetrack 49/04c-7Y was initially intended to target the Lower Carboniferous units. To maximize reservoir contact, the well was initially planned to be completed with four to five hydraulic fractures, with a minimum of one per target unit. Because of the proximity to the gas/water contact, the decision was made to complete the well with a cased-and-cemented liner and plug-and-perforation technique for placement and isolation of the hydraulic fractures. Previous experiences with openhole uncemented multistage systems have positively affected the efficiency of hydraulic-fracturing execution in the North Sea. Also, previous experience of spalling and out-of-gauge hole was another driver toward a cemented system.