The Jauf formation of Bahrain's Awali brownfield is currently underdeveloped due to an extremely challenging geological environment. Because of high heterogeneity, the formation requires fracturing to produce economically. However, the Jauf sandstone is unconsolidated, and formation sand production does not allow for high gas rates. A combined solution was introduced using a completion assembly with frac ports and screens to restrict sand production with a tip screenout approach in the stimulation stage. The studied well was completed with a 4 1/2-in. cemented liner that had been plugged and abandoned and left with 7 5/8-in. casing across the prolific Jauf sandstone. A completion string with screens and production sleeves, fracturing ports, and packers was deployed to compartmentalize and fracture the Jauf. Fracturing ports, while production sleeves were later manipulated with coiled tubing (CT) to allow production across the sleeve filter media, thereby preventing proppant or formation sand from being produced. A large fracturing treatment was placed in an aggressive tip-screenout mode to achieve optimum fracture length and maximize fracture conductivity. Afterwards, CT was used to close the fracturing port and open the screen ports to flow back the well and proceed with testing operations. A hydraulically activated shifting tool was used to manipulate the fracturing ports (open and closed) as well as the production ports enabling gas production through the included screens. This technology enabled the fracturing operation to be executed in conjunction with sand management hardware during production, further providing more flexibility for future intervention operations when compared to frac-and-pack type assemblies. Considering the significant depth of the formation (11,700 ft), degradable fibers were used to minimize friction pressure and, respectively, maximize fracturing treatment rate to allow for optimum height coverage and lateral fracture penetration. The post-stimulation sand-free gas production rate through the screens was greater than 20 Mscf, which was confirmed with choke-variability testing operations conducted after manipulation of the completion ports. The trial well proved that proppant fracturing combined with innovative sand control hardware provides an effective method for producing gas from the prolific Jauf reservoir. The described completion system represents an alternative to a traditional frac-and-pack hardware solution, enabling full control of the well with CT interventions. A tailored stimulation design and advanced placement technique coupled with detailed description of completion design and operations sequence will be of interest to experts dealing with tight unconsolidated formations in the Middle East and other regions.

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Permeability is a fundamental petrophysical attribute required to accurately evaluate recoverable reserves and design an appropriate field-development strategy. Because logging tools do not measure absolute permeability, minimizing uncertainty in the evaluation of log-derived permeabilities remains one of the most critical petrophysical challenges in the oil industry. Horizontal development in laterally heterogeneous carbonate reservoirs also requires evaluation of lateral permeability variations to optimize completion design, while maximizing reservoir exposure via precise well placement in real time. This paper demonstrates innovative methods to evaluate lateral permeability variations in heterogenous carbonate reservoirs. The workflow for log-derived permeability predictions is based on empirical relationships using nuclear magnetic resonance (NMR), acoustic, and high-resolution imaging tool measurements. These are normalized in an integrated multi-disciplinary approach using core, well test, production logs, and formation-tester mobility data where available. Traditionally, formation-tester tools have been used to obtain single pressure and mobility values at each test station. The logging-while-drilling (LWD) formation tester can be oriented azimuthally to help evaluate permeability anisotropy, which is a key factor for reservoir characterization in laterally heterogeneous reservoir layers. The oriented data can also be used to adjust the well plan in real time to maximize reservoir exposure in the desired "sweet spot." Variations in the oriented LWD formation tester measurements at each depth station exhibited favorable correlations to azimuthal changes observed in the LWD high-resolution micro resistivity image. Detailed image analysis further helped to understand the mechanism that governs the azimuthal permeability profile. The combination of oriented LWD formation-tester and high-resolution image data also aided in making better real-time geosteering decisions, as well as in the planning and design of a future field-development program within the local reservoir sector. Operational considerations to maximize data quality rely on an optimized bottomhole assembly (BHA) design, accurate depth control, and robust orientation techniques based on best practices and lessons learned. This paper presents an integrated approach for well placement and an improved understanding of flow-unit characterization via first-time use of oriented formation-tester data in conjunction with corresponding high-resolution images in a laterally heterogeneous reservoir.

A methodology to determine water contamination levels prior sampling to guarantee the capture of representative water samples, as its highly crucial for understanding saturation profile, reservoir reserves & field development planning. The presence of low salinity mud while trying to sample low salinity water adds further challenges in acquiring a clean sample. Especially, that the resistivity measurement sometimes won't have a resistivity contrast. Nevertheless, the conventional optical density measurement won't be able to differentiate the two water types. Applying power law model and utilization of resistivity/conductivity and density measurements to quantify contamination levels as the fluid property in miscible filtrate & formation water will match such transition profile. Since both water base mud filtrate (WBMf) & formation water exhibit the same optical spectroscopy response, it will be quite challenging to differentiate between them. Hence, the above method is used to quantify accurate contamination. The pH measurement was also used to monitor rate of change & stabilization across pump out station whenever there's no contrast in salinities between WBMf & formation water. The contamination calculations process can be divided into four steps: Firstly, exponent selection for the power law which depends on the inlet selection, either radial probe or single probe. Secondly, determination of filtrate properties (initial end point). Third, flow regime identification diagnostics after power law fitting. Fourth, end point extrapolation. The resistivity/conductivity, density and pH measurements were utilized during down hole fluid analysis of water stations to evaluate the contamination levels using the power law model in a shallow carbonate environment. The model was tried for multiple inlets radial probe & single probe using different power law exponents. The results were consistent and determined the right timings to sample clean water bottles with minimum contamination levels to be analyzed at the lab. Hence, providing accurate geochemical analysis for the reservoir's field development planning and optimizing station time and avoiding unnecessary pump out in real time which saves time and cost.

Carbonate reservoir complexity imposes some challenges in formation evaluation and characterization. Grain, pore, and throat size distributions play major roles in rock typing to understand static and dynamic behaviors of carbonate reservoirs. Special core analysis techniques, such as MICP and digital core imaging, revealed that the presence of different types of pore structures can be classified based on sizes as micro, meso and macro pores. This paper explores a unique inversion technique using nuclear magnetic resonance (NMR) data to deliver fast, accurate, and continuous pore typing across logged intervals. The traditional NMR data processing technique consists of sequential steps that ultimately convert echoes from time domain into T2 domain using an exponential inversion, also known as Laplace transform. NMR-gamma inversion (NMR-GI) workflow is a mathematical approach to process the NMR data using probabilistic functions. The gamma inversion function has a form of a bell curve with the base in the logarithmic x-axis. Unlike exponential inversion technique, this inversion produces multiple components. Each component is located at a particular time and it is labeled with a specific number, which reflects the T2 time stamp of each component. The individual area under each component is translated into porosity units. The application of gamma inversion in a T2 spectrum results in subcomponents via deconvolution of the original spectrum. The display of the components makes it easy to visually analyze and interpret the porosimetry for pore size distribution and group the components for pore typing. A deeper look into the different components of the T2 spectrums enlarges the NMR measurement portfolio by displaying the porosimetry and pore size distribution. The inverted T2 results from both logging while drilling (LWD) and wireline tools in different fields are consistent with the reservoir geological and petrophysical models. The added value of this technique can be tangible for geophysical and geological (G&G) applications as well as completion design optimization. The NMR-GI technique can be further utilized and calibrated to improve reservoir understanding and optimize advanced core analysis by providing a quick continuous carbonate pore and rock type log.