Multiply-fractured horizontal wells are an efficient way to produce from tight gas, shale gas and tight oil formations. In this work, we present a linear composite model with a dual porosity inner zone to model production from a multiple fractured horizontal well. The composite solution uses linear dual porosity flow solution for the inner reservoir and a linear single porosity solution for the outer reservoir combined with continuity of pressure and flux at their interface. Solution to the problem was obtained in Laplace space. The solution that we have obtained is simple and fast, yet effective and can be applied to model production from fractured horizontal wells. For the cases of interest, we observe three linear flow periods in this model. The first linear flow is from the fractures into the wellbore, followed by linear flow in the matrix to the fractures and lastly linear flow in the outer single porosity reservoir to the inner reservoir. Each of these three linear flow periods is separated by a transition depending on the properties of the fracture, matrix and the outer reservoir. We use a numerical simulator to examine the validity of some of the assumptions made in the development of the work. While the model that we have made consists of only linear flow solutions, the numerical model accounts for two dimensional flows in all media. New solutions are presented in the form of type curves.
Liquid-rich shale (LRS) gas reservoirs have gained increasing attention in recent years. The Eagleford Shale in the U.S. and the Duvernay Shale in Canada are examples of liquid-rich shale gas plays which are being exploited to produce more profitable liquid hydrocarbons with natural gas. These reservoirs may store liquid hydrocarbons in liquid or vapor state, as with gas condensate systems. Further, shale gas reservoirs may contain significant volumes of organic matter, which stores gas (and liquid hydrocarbons) in the adsorbed state.There have been several historical simulation studies investigating the impact of various reservoir and fluid properties on fluid production and recovery from LRS, however none have investigated the importance of desorption. Adsorption has previously been suggested to be an important storage mechanism in organic-rich shales, particularly for heavy hydrocarbon fractions. Matrix pore configuration and associated connectivity has also been previously demonstrated to be an important control on gas production from shale gas reservoirs, but the impact on condensate production has not been investigated for LRS.In this work, the impact of heavy hydrocarbon fraction desorption, pore configuration and connectivity, fluid composition and operating conditions (flowing bottomhole pressure) on LRS production is investigated using a commercial simulator. We use PVT data from previous studies to develop a compositional simulation model analog of an LRS reservoir. Hydrocarbon component adsorption amounts are modeled using the Langmuir isotherm. Different combinations of organic and inorganic matter and fracture porosity, and their connectivity, are also assigned in the simulation cases.Simulation sensitivities demonstrate that desorption can contribute significantly to condensate production, depending on fluid composition and pore connectivity. In cases where liquid-fraction adsorption contributes significantly to in-place volume, we recommend injection of light end gases to mitigate condensate blockage. This will be studied in detail in future work.
Different approaches and techniques were utilized in the industry to overcome challenges in sanding formations, including frac-packs, indirect fracturing, and resin coated proppants. Due to complexities in the results achieved, open hole multistage fracturing (OH MSF) with a sand control completion system was introduced with the goal of expanding the technology portfolio for controlling sand production and proppant flowback. Offset wells drilled in a prolific gas-bearing unconsolidated sandstone formation showed high sand and proppant production restricting the potential from these wells. Therefore, it was necessary to develop a new OH MSF completion strategy to address sand/proppant control and combine it with proppant fracturing at the same time. This paper highlights OH MSF technology that utilizes screened port sleeves capable of withstanding fracturing pressures and harsh environments. The new completion system consists of a hydraulic frac port opened by applying pressure in the first stage. In addition, the fracturing ports for the next stages are opened by dropping activation balls. Each stage needs to be equipped with a sleeve fused with a screen for sand and/or proppant control. Stages are separated by open hole packers for zonal isolation in the open hole section. It is an innovative system that combines MSF completion with sand control components. Due to the complex nature of the completion, rigless well intervention operations must be well planned, discussed, and conducted with close monitoring during all the operations. In particular, frac port opening/closing, sand screened sleeves opening with coiled tubing (CT) well interventions, proppant fracturing operations, and e-line production logging tools (PLTs). Besides, if the transmissibility is high with a high leak off and quick closure of fracture, then frac operations should be performed with the objective of creating a tip screen out (TSO) scenario to achieve good proppant packing close to the wellbore area. Production rates after completing proppant fracturing, CT milling, and shifting interventions exceeded the expectations without any sand or proppant flowback. The candidate well's rate remained higher than offset wells and no sand nor proppant were observed on the surface. The new OH MSF with sand control completion technology will enable performing OH MSF treatments in gas formations with a high sanding tendency. In addition, it helps to diversify technologies utilized to enhance production without producing formation sand or proppant. Utilization in the right candidate in conjunction with an optimum engineering approach and optimized design will ensure obtaining the benefits of this new completion system to overcome similar challenges.
Post-fracturing cleanup and production revival in sub-hydrostatic wells can be challenging. The complexity is amplified in sub-hydrostatic multistage horizontal wells because, by the time the fracturing treatment is concluded, the gas phase of the energized fracturing fluids used during the initial stages of the fracturing treatment dissipates. In the subject sub-hydrostatic well, coiled tubing (CT) with a real-time telemetry system was utilized over a standard nitrogen lifting intervention utilizing conventional CT to revive a hydraulically fractured well due to its capabilities to enable real-time decisions using live bottom-hole data. Acid fracturing using an energized fluid treatment was conducted in the subject gas well completed with a multistage open-hole completion system using isolation packers and sleeves. As the subject well was sub-hydrostatic, it was decided to utilize the CT with real-time telemetry system to gain value from its associated downhole parameters during the cleanup phase to alleviate the chances of successfully lifting the well. The well was placed in an area with prolific offset producers; hence, there were high production expectations from this well. A review of the well indicated a decreasing trend of reservoir pressure from heel to toe of the lateral, possibly contributing to lower stresses and potential crossflow between stages. Hence, the diverter concentrations and volumes per stage and nitrogen rates were maximized for each new fracturing stage to attempt to create new fractures. Considering the challenges with the well, it was essential that the N2 lifting operation parameters should be optimized to enhance drawdown. It was decided to utilize CT with a real-time telemetry system to control drawdown parameters better and maximize the possibility of success. Real-time downhole pressure measurements were utilized to accurately identify the fluid gradient followed by real-time evaluation and monitoring of the well behavior during N2 lifting operations. The real-time downhole data collected enabled on-the-fly intervention optimization leading to transforming the well into an economic producer. The integrated post-treatment analysis workflow provided a robust insight into fracture treatment design and evaluation, reservoir imbibition perspective, openhole completion practices, and the importance of real-time telemetry for challenging interventions. The lessons learned that are presented in this paper could act as a guide to contribute to operational efficiency enhancements and cost savings in other projects.
In most cases several folds of increase in production after a fracturing treatment is sufficient testimony to the success of the technology and its application in the particular well or field. A cursory look at a post-frac, pressure transient analysis (PTA) will show a stimulated well condition and validate the achievement. For a proper assessment of well potential this approach may be inadequate. The fracture geometry, conductivity, phase flow through the reservoir, reservoir quality, completion practices and pressure behavior under the boundary conditions all contribute to a well's performance. With all these factors considered, the post frac production results may be significantly different from expectations. To encompass this, the preferred methodology would be to benchmark the production from different fractured wells to have a valid comparison and then optimize the methods. Production-history matching through reservoir simulation is a very effective tool in meeting this challenge. Many subtle features of the reservoir get highlighted in relation to hydraulic fracturing with the dominant component being the fracture itself. This paper examines several successful wells, which unexpectedly fell below the benchmark. The study investigates whether the hydraulic fracture underperformed or the post-frac activities contributed to low well deliverability. Conventional hydraulic fracturing and the newer technique of channel fracturing were part of this analysis. The post-frac flowback procedures had a significant impact on the productivity of the wells. The presence of condensate brought its own set of challenges. In the long term, it was also interesting to note how the wells recovered after these damages. This paper will provide an insight into this investigation.
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