SPE Members Abstract This paper summarizes MetFuel Inc.'s experiences in conducting a pilot test of the coalbed methane potential of an undeveloped area in the southern Black Warrior Basin. The pilot project was designed to gather baseline reservoir data, determine the project was designed to gather baseline reservoir data, determine the viability of further development by field experience, and learn how to complete and stimulate coal seams in this area. The pilot project provided valuable insights in terms of drilling practices, defining provided valuable insights in terms of drilling practices, defining target intervals, hydraulic fracture geometry and height growth, perforation placement, canister test procedures, and reservoir perforation placement, canister test procedures, and reservoir permeability versus stress. A wealth of baseline reservoir data was permeability versus stress. A wealth of baseline reservoir data was also collected. Continued production from the pilot project wells is required to determine the economic viability of large-scale development in this area. Introduction MetFuel, Inc. is developing a coalbed methane prospect in the relatively undeveloped southern portion of the Black WarriorBasin. Before developing a coal seam in a new area, a pilot program should be implemented to gather data so the feasibility of full scale development can be evaluated. Key factors to be determined to optimally design the large scale development project are gas content and formation permeability. This pilot project has been designed to (1) gather baseline reservoir data, (2) determine the viability of further development by field experience, (3) provide insights into potential operational problems involved with drilling and potential operational problems involved with drilling and completing wells in this area, and (4) learn how to complete and stimulate the coal seams in this area. A five-spot pilot has been drilled in the Big Bend area of Black Warrior Basin to accomplish the goals set forth. The location of the five-spot pilot project in relation to other coalbed methane activity in the basin is shown in Fig. 1. This paper presents a status report on the pilot project. At the time of this writing, we do not have any long term production data because no water disposal facilities have been production data because no water disposal facilities have been installed in the area of the five-spot pattern. As such, we have only included information concerning the various completion and stimulation methods chosen for the pilot wells. Only time and long term production data will allow us to properly evaluate the completion methods tested in the pilot project. PILOT PROJECT DESIGN PILOT PROJECT DESIGN Because coalbed methane well production depends on the interference from adjacent producing wells to reduce reservoir pressure over a large scale area in order to initiate gas desorption, pressure over a large scale area in order to initiate gas desorption, a five-spot pilot project was designed to test the potential productivity of the coals found in the Big Bend area of the Black Warrior productivity of the coals found in the Big Bend area of the Black Warrior Basin. Six possible target coal seams are available for completion as shown in the generalized stratigraphic column in Fig. 2. The locations of the pilot project wells are shown in Fig. 3. A goal of the pilot project was to define the zones of highest potential for completing in a large scale development project. potential for completing in a large scale development project. Therefore, the pilot wells were drilled through all of the six potenial target seams. The average total depth (TD) for the pilot wells was potenial target seams. The average total depth (TD) for the pilot wells was approximately 5300 feet. Because we wanted to determine the permeability and productivity of individual target coal seams, each permeability and productivity of individual target coal seams, each of the pilot wells was cased and cemented to TD as shown in Fig. 4. The original pilot project design called for isolated well testing and production testing of each of the six target coal groups in each of the five pilot wells. It was quickly discovered that this idealized approach was impractical because injection/fall off testing of individual seams requires one to two weeks and production testing of individual target seams can take as much as three months of uninterrupted production. Because the J coal seams require, significant additional drilling (and costs) to complete, the testing of the potential of the J-seam was given a high priority. The reasoning for this being that if we could determine that the J-seams are not potentially productive, tremendous savings could be achieved in drilling costs of additional development wells. Therefore, the J-seams were tested using injection/falloff tests and completed and produced for one to two months in an isolated fashion in the first two wells drilled in the pilot program. pilot program. P. 487
The rise in unconventional resource exploration relies on strategically placed sensors to record critical information during multiple forms of testing and reservoir enhancement techniques. The accurate data gained during the testing phases are what ultimately lead to the best flow regime design and successful optimization of the resources. New completion design or reservoir stimulation techniques are also effectively evaluated using data acquisition, aiding the development, refinement, and implementation of these techniques. Subsequently, suspension of the sensors in wellbores without decreasing flow can be challenging when introducing new techniques or modifications. Additionally, these flow rate conditions can prevent the determination of production at the most economically advantageous time and rate. This paper examines difficulties associated with acquiring data that can exist because of new completion designs or exploratory methods tested as a means to optimize a resource's economic viability. Solutions offered by a new highexpansion hanger that can be used to meet these difficulties are also discussed. The tool has been proven to be a durable and flexible solution for an increasing array of completion and reservoir enhancement techniques for many styles and types of well testing under varying pressures and conditions. The tool is available in a wide range of pipe sizes and types, enabling positioning inside liner sizes of larger inside diameter (ID) than that of the uphole completion tubing string within the wellbore. The high-expansion design also provides the assembly a generous bypass flow area, which helps increase the accuracy of the data received during flowing events.Case histories are presented to illustrate the varying range of situations where the high-expansion hanger has been proven both a viable and valuable solution for reservoir analysis and optimization.
Hydraulic fracturing is recognized as a successful stimulation technique used to enhance recovery from reservoirs. Prediction of fracture initiation and propagation from wellbores is necessary for efficient hydraulic fracturing stimulation tasks. Perforating is key to the success of a hydraulic fracturing treatment; it provides a means of communication between the wellbore and reservoir. Additionally, in a fracturestimulated reservoir, the perforations serve as fluid conduits between the fracture and wellbore.Once the fracture is created, perforations provide the entrance to the fracture for the proppant. The perforation diameter must be sufficient to help prevent bridging because an accumulation of proppant can block the entrance hole. Inadequate perforations, low perforating efficiency, and variations in perforation entrance hole diameter can increase the effects of near wellbore (NWB) tortuosity and leave several holes that do not contribute to stimulation, causing uneven treatment distribution, increased formation breakdown pressure, and suboptimal completion-occasionally beyond the pressure capability of the surface equipment or design rating of the well.A new class of shaped charges engineered to maximize hole diameter while maintaining a consistent exit hole diameter independent of well profile and/or gun eccentricity has recently been introduced for unconventional resources requiring stimulation. Designed for perforating before a hydraulic stimulation, these new charges can help reduce the probability of screenout during the fracturing process.This paper describes the new charge technology in detail and addresses its successful deployment during fracturing of tight gas wells in Saudi Arabia. Specific examples are used to illustrate how the system facilitates prefracture evaluation, fracture initiation, and how fracture tortuosity and perforation friction entry values are decreased compared to previous perforating systems.
This paper highlights the first successful application of a field deployment of a high-temperature (HT) downhole shut-in tool (DHSIT) in multistage fracturing completions (MSF) producing retrograde gas condensate and from sour carbonate reservoirs. Many gas operators and service providers have made various attempts in the past to evaluate the long-term benefit of MSF completions while deploying DHSIT devices but have achieved only limited success (Ref. 1 and 2). During such deployments, many challenges and difficulties were faced in the attempt to deploy and retrieve those tools as well as to complete sound data interpretation to successfully identify both reservoir, stimulation, and downhole productivity parameters, and especially when having a combination of both heterogeneous rocks having retrograde gas pressure-volume-temperature (PVT) complexities. Therefore, a robust design of a DHSIT was needed to accurately shut-in the well, hold differential pressure, capture downhole pressure transient data, and thereby identify acid fracture design/conductivity, evaluate total KH, reduce wellbore storage effects, properly evaluate transient pressure effects, and then obtain a better understanding of frac geometry, reservoir parameters, and geologic uncertainties. Several aspects were taken into consideration for overcoming those challenges when preparing the DHSIT tool design including but not limited to proper metallurgy selection, enough gas flow area, impact on well drawdown, tool differential pressure, proper elastomer selection, shut-in time programming, internal completion diameter, and battery operation life and temperature. This paper is based on the first successful deployment and retrieval of the DHSIT in a 4-½" MSF sour carbonate gas well. The trial proved that all design considerations were important and took into consideration all well parameters. This project confirmed that DHSIT devices can successfully withstand the challenges of operating in sour carbonate MSF gas wells as well as minimize operational risk. This successful trial demonstrates the value of utilizing the DHSIT, and confirms more tangible values for wellbore conductivity post stimulation. All this was achieved by the proper metallurgy selection, maximizing gas flow area, minimizing the impact on well drawdown, and reducing well shut-in time and deferred gas production. Proper battery selection and elastomer design also enabled the tool to be operated at temperatures as high as 350 °F. The case study includes the detailed analysis of deployment and retrieval lessons learned, and includes equalization procedures, which added to the complexity of the operation. The paper captures all engineering concepts, tool design, setting packer mechanism, deployment procedures, and tool equalization and retrieval along with data evaluation and interpretation. In addition to lessons learned based on the field trial, various recommendations will be presented to minimize operational risk, optimize shut-in time and maximize data quality and interpretation. Utilizing the lessons learned and the developed procedures presented in this paper will allow for the expansion of this technology to different gas well types and formations as well as standardize use to proper evaluate the value of future MSF completions and stimulation designs.
This paper is a case study of a successful, complex, high-pressure, and heavy-duty fishing job on a live sour gas well in Saudi Arabia. The multidisciplinary effort involved braided line, various sizes of slick line and coiled tubing (CT) intervention. The paper examines details of the job planning and design as well as the job execution. The well control philosophy and compliance to some of the highest operational standards in the industry will be discussed along with the associated risk and mitigation strategy. This multifaceted job involved fishing a live perforating gun and plug assembly, which was stuck in the liner following a misfire while attempting to set the plug. The fishing job was further complicated due to the presence of a parted section of electric line on top of the original fish. Recent developments in heavy-duty fishing operations were incorporated into the intervention process. Equally important is the integrated approach used for this complex fishing job with special safety procedures put in place for the use of multilevel scaffolding, multiple cranes, lifting plans, wire and live gun retrieval procedures, contingency plans and multipurpose pressure control equipment (PCE). Lessons learned will also be presented in the paper. This successful heavy-duty fishing operation has helped push the boundaries of rigless well intervention, improved operational efficiency and opened up additional opportunities for this technology that previously required the deployment of a workover rig or snubbing unit.
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