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The clastic non-associated gas reservoirs are encountered in one of the Saudi Arabian oilfields. There is a wide variation in permeability in this Devonian age formation, varying from tight rocks with 0.1 md or less to more than few Darcie's in highly unconsolidated sandstones. While the prolific areas are easily producible at sustained high gas rates by conventional drilling and using sand control completion mechanisms, the relatively tighter areas require hydraulic fracturing to sustain commercial flow rate. During the last 10 years, the field A focused on exploiting gas reservoirs is being developed with vertical or S-shaped wells, and completed using a monobore tubular assembly. Proppant fracturing treatments are routinely conducted in multiple stages along the vertical wellbore. Fracture treatment parameters are adjusted over time by the introduction of different fracture fluids to enhance stability and avoid premature screen out. Proppant flow back measures were taken with the use of resin-coated proppants. A large database was developed on stimulation treatments and results that allowed conducting a detailed analysis to understand the behavior and effect of hydraulic fracturing trends on the reservoir performance to optimize the design parameters and further increase reservoir potential. This paper documents the analysis of the pre- and post-fracture treatment data, production analysis and thorough evaluation of petrophysical and geomechanical measurements from this massive database of 10-year long operational period. This study shows that there is a room to improve fracturing treatments and fluid chemistry and recommends a step change in the well stimulation strategy by modifying some existing technologies and also applying novel technologies that have been carefully studied and approved using laboratory and field trial testing. The results from the application of this new strategy are presented in the paper using actual examples.
The clastic non-associated gas reservoirs are encountered in one of the Saudi Arabian oilfields. There is a wide variation in permeability in this Devonian age formation, varying from tight rocks with 0.1 md or less to more than few Darcie's in highly unconsolidated sandstones. While the prolific areas are easily producible at sustained high gas rates by conventional drilling and using sand control completion mechanisms, the relatively tighter areas require hydraulic fracturing to sustain commercial flow rate. During the last 10 years, the field A focused on exploiting gas reservoirs is being developed with vertical or S-shaped wells, and completed using a monobore tubular assembly. Proppant fracturing treatments are routinely conducted in multiple stages along the vertical wellbore. Fracture treatment parameters are adjusted over time by the introduction of different fracture fluids to enhance stability and avoid premature screen out. Proppant flow back measures were taken with the use of resin-coated proppants. A large database was developed on stimulation treatments and results that allowed conducting a detailed analysis to understand the behavior and effect of hydraulic fracturing trends on the reservoir performance to optimize the design parameters and further increase reservoir potential. This paper documents the analysis of the pre- and post-fracture treatment data, production analysis and thorough evaluation of petrophysical and geomechanical measurements from this massive database of 10-year long operational period. This study shows that there is a room to improve fracturing treatments and fluid chemistry and recommends a step change in the well stimulation strategy by modifying some existing technologies and also applying novel technologies that have been carefully studied and approved using laboratory and field trial testing. The results from the application of this new strategy are presented in the paper using actual examples.
Cross-linked gel hydraulic fracturing fluid can induce high damage in the fracture when left for a long period of time. Any residual gel not produced back reduces the conductivity of the fracture and the well productivity, leading to an extended flowback for cleanup operation, which is not cost-effective.The objective of this study is to assess cleanup operation effectiveness by conducting laboratory testing on the flowback fluid samples from hydraulically fractured wells. These development wells are located in a clastic gas field in Saudi Arabia. This Devonian age reservoir has a range of permeability varying tight rocks of 0.1 md that require stimulation to highly prolific rocks with more than a Darcy that produce naturally. The laboratory analysis technique that was used for assessing the cleanup effectiveness is based on determination of the polymer content in the flowback fracturing fluid with a size exclusion chromatography (SEC). This laboratory technique provides the polymer concentration in the return fluid in a series of samples collected throughout the cleanup operation, and based on its results coupled with the production performance, the polymer strength of the residual fracturing fluids can be inferred. This study shows that the SEC technique is effective in qualitatively determining the polymer concentration trend with the flowback time, to assess the residual polymer content. The results are useful in establishing trends for the effective flowback practices based on different reservoir and fracture characteristics, even if fracturing fluids contain breaking agents. Using the laboratory results to optimize these parameters, formation damage can be minimized and well productivity will be ultimately enhanced.This paper summarizes results from the chemical analyses of the flowback fluids from three gas wells that help establish the basis for the flowback cleanup behavior, matched with the reservoir characteristics, fracturing design, fracturing fluid formulations; and concludes with operational recommendations. This study was conducted for the first time in this field with the goal of optimizing flowback duration and cost, and minimizing formation damage; and thereby enhancing well productivity.
A clastic gas reservoir, have been characterized of being unconsolidated in nature, as well as its complexity and heterogeneity. Regarding to the ability to transmit fluids, this reservoir is predominantly tight with a wide variation in the permeability range, which confirms its heterogeneity. The depositional environment interpretation suggests the presence of channels running from West to East direction with kind of limited lateral extension. In terms of well completion strategy, most of the wells have been proppant fractured to produce at sustainable rates. Pressure transient analysis (PTA) has been applied extensively to better characterize and understand the reservoir behavior, well performance and to obtain significant properties of the reservoir. The challenges of this work consisted of performing a critical review of the existing PTA to identify some common behaviors or general trends in the pressure response. Considering the PTA have assessed the same reservoir and that several wells have been completed with similar completion techniques was expected finding similar pressure response behaviors. This paper presents different cases that have been analyzed through PTA, summarizing common trends, in terms of reservoir behavior and well response that have been observed during the study. The outputs of this study were used as inputs for the simulation reservoir models to narrow the uncertainty in some reservoir and wellbore properties and as inputs for the static model construction to better understand or confirm geological assumptions. The results of the PTA interpretation also helped to successfully drill newer wells away from any geological complexity and achieved the planned target of gas rates.
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