ALBERT

Description: Horizontal wells are often drilled and hydraulically fractured in tight reservoirs to produce hydrocarbons or heat. Different fracturing fluids such as slick water, gas, foam, gel, or a combination can be used with slick water being the most common fracturing fluid. In this paper, we study the impacts of different fracturing fluids on fractured well productivity using an in-house integrated hydraulic fracturing and reservoir simulator with an equation-of-state compositional model. We analyzed the fracture geometry, stress interference, proppant placement, and the subsequent well productivity using different fracturing fluids. The results clearly show that different fracturing fluids result in very different fracture shape, sand distribution, and water and hydrocarbon production. By conducting fracturing and production simulations in one simulator, we ensure that no physics and data loss occurs due to data migration between two different software packages for hydraulic fracturing and reservoir simulation. To the best of the authors’ knowledge, this is the first time that a single integrated equation-of-state compositional hydraulic fracturing and reservoir simulator has been presented and applied for well lifecycle simulation.

Description: The research has shown successful application of ionic liquids (ILs) as drilling fluid additives for modifying the mud rheology. Ionic liquids are tuneable solvents comprising of hundreds of combination of various cations and anions. The cationic portion mainly comprises of a side alkyl chain which plays an important role in altering the drilling fluid properties. This review mainly focusses on finding the impact of alkyl chain length on yield point, plastic viscosity and filtration properties of water based mud at room temperature. The paper also incorporates the X-ray diffraction (XRD) analysis carried out on various ionic liquids by different research groups which confirms how the intercalation between ionic liquid and Na-Bt (Sodium Bentonite) changes the structure of clay and thus alters the rheology of the mud. It can be concluded that ionic liquids act as rheology modifiers by intercalating between the clay layers and thus changing the d-spacing of the clay. Moreover, the hydrophobicity, polarity and solubility of alkyl chain play an important role in altering the wettability and dispersion behavior of clay which modify the filtration as well as rheological properties of the mud.

Description: Quantitative characterization of pore structure and analysis of influencing factors of methane adsorption are important segments in shale gas reservoir and resources evaluation and have not been systematically carried out in marine–continental shale series. A series of integrated methods, including total organic carbon (TOC) contents, Rock-Eval pyrolysis, mineral composition analysis, pore structure measurement, high-pressure CH4 adsorption analysis and FE-SEM observation, were conducted on 12 transitional shale samples of well WBC-1 in the southern North China Basin (SNCB). The results indicate that TOC contents of the transitional shales range from 1.03 to 8.06% with an average of 2.39%. The transitional shale consists chiefly of quartz, white mica and clay minerals. Interparticle pore, intraparticle pore, dissolution pore and microfracture were observed in the FE-SEM images. The specific surface area (SSA) of BET for the samples ranges from 3.3612 to 12.1217 m2/g (average: 6.9320 m2/g), whereas the DR SSA for the samples ranges from 12.9844 to 35.4267 m2/g (average: 19.67 m2/g). The Langmuir volume (VL) ranges from 2.05 to 4.75 cm3/g (average = 2.43 cm3/g). There is unobvious correction between BET and DR SSA with TOC contents, which means inorganic pores are the main component of pore space in the transitional shale from the SNCB. The relationship of SSA and pore volume shows that micropore has a greater impact on the CH4 adsorption capacity than mesopore–macropore in the transitional shale. Different from shales in other petroliferous basin, clay minerals are the primary factor affecting adsorption capacity of CH4 for transitional shale in this study. The pore structure of the transitional shale for this study is characterized by higher fractal dimension and more heterogeneous pore structure compared to shale in other petroliferous basin. This study provides an example and new revelation for the influencing factors of pore structure and methane adsorption capacity of marine–continental transitional shale.

Description: Porosity is the dominant factor that determines the exploitable capacity of sedimentary reservoir rocks. Generally, pore heterogeneity is poorly represented in subsurface geological models due to the complexity. Granular mixtures produce complex pore space controlled by grain size, grain shape, and grain sorting. Heterogeneities in pore space volume are present at micro- and nanoscales in granular mixtures due to packing conditions resulting from deposition and diagenesis. In the present study, three-dimensional packing models were generated to provide a realistic description of granular mixtures. Accordingly, this study presents static packing models for unit cells idealised for spherical and elongated grains using cubic, orthorhombic, and rhombohedral packing models. Subsequently, the grain shape effects in terms of elongation degree and grain size distribution in terms of the degree of sorting were evaluated. The mixing effect on the inter-granular porosity for each unit cell packing model was analysed. A range of porosity values was derived using grain parameters generated through in-house developed MATLAB codes from digital FESEM images of sandstone samples. Our study demonstrates that actual grain size does not influence porosity, but for real sandstone samples, the sorting and shape of grains affect porosity values. The range of porosity values estimated by this method can be realistic at the basin level as the grain shape effects replicate sediment maturity. The developed method can be adopted in the distributed spatial models on porosity, especially for basin-scale hydrocarbon resource estimation.

Description: The perforating technique is one of the well completion methods and a final stage that helps connect reservoir formation to wellbore during hydrocarbon production. The present work aimed to determine the effect of the perforated casing completion on the pressure gradient and perforation skin factor in the vertical near-wellbore region. This work presented a novel experimental approach for studying the effect of perforation parameters on hydrocarbon production by creating a prototype representing the near-wellbore region. The study conducted extensive laboratory testing to create two prototype artificial samples for a cylindrical near-wellbore region, open hole, and perforated casing sample. An experimental test was carried out using a geotechnical radial flow setup to measure the differential pressure in the two samples; the single-phase (water) was radially injected into the core sample within the same flow boundary conditions. Numerical simulation and statistical analysis were used to expand the investigation of the effect of the dimensions and distribution of perforations on the perforation skin factor and the pressure gradient in the cylindrical near-wellbore region. The results showed a clear view of the effect of the perforations’ parameters on the pressure gradient in the vertical near-wellbore region. In addition, two novel correlations were produced from statistical analysis that simplified the estimation of the perforation skin factor in the perforated casing completion. This study will help to clarify and understand the effect of perforation parameters on well productivity.

Description: With the development of gas well exploitation, the calculation of wellbore with single-phase state affected by single factor cannot meet the actual needs of engineering. We need to consider the simulation calculation of complex wellbore environment under the coupling of multiphase and multiple factors, so as to better serve the petroleum industry. In view of the problem that the commonly used temperature and pressure model can only be used for single-phase state under complex well conditions, and the error is large. Combined with the wellbore heat transfer mechanism and the calculation method of pipe flow pressure drop gradient, this study analyzes the shortcomings of Ramey model and Hassan & Kabir model through transient analysis. Based on the equations of mass conservation, momentum conservation and energy conservation, and considering the interaction between fluid physical parameters and temperature and pressure, the wellbore pressure coupling model of water-bearing gas well is established, and the Newton Raphael iterative method is used for MATLAB programming. On this basis, the relationship between tubing diameter, gas production, gas–water ratio, and wellbore temperature field and pressure field in high water-bearing gas wells is discussed. The results show that the wellbore temperature pressure coupling model of high water-bearing gas well considering the coupling of gas–liquid two-phase flow wellbore temperature pressure field has higher accuracy than Ramey model and Hassan & Kabir model, and the minimum coefficients of variation of each model are 0.022, 0.037 and 0.042, respectively. Therefore, the model in this study is highly consistent with the field measured data. Therefore, the findings of this study are helpful to better calculate the wellbore temperature and pressure parameters under complex well conditions.

Description: The Chang 7 oil group in the Ordos Basin has the characteristics of a tight lithology, a low formation pressure coefficient and strong reservoir heterogeneity. To better determine reasonable developmental technical countermeasures, oiliness, seepage capacity, and compressibility evaluations are combined. Using a combination of field practice and laboratory experiments, six types of sweetness classification evaluation parameters are screened: oil saturation, longitudinal oil layer structure coefficient, average pore throat radius, gas-oil ratio, brittleness index, and minimum horizontal principal stress. By combining the relationships among variables with the initial production from directional wells, the gray correlation method is used to quantify the weights of the contributions of evaluation parameters to production. On this basis, using the difference method for the curve slope, a sweetness evaluation and classification method for the Chang 7 oil group is constructed, and it solves the difficult problem of quality difference classification for the Chang 7 oil group and provides a reference basis for the optimal design of well patterns and fracturing reconstruction parameters.

Description: This study introduces a comprehensive and cost-effective approach to diagnose and treat the asphaltenes precipitation problems in different downhole conditions. The proposed approach has been successfully applied in two oil wells (Well-I, and Well-II) located in the Western Desert of Egypt. The two wells produce oil of moderate to high oil gravity with low asphaltenes content using Electrical Submersible Pumps (ESP). In such operating conditions, solid deposits caused blockage at the pump intake and within the pumping stages in the two wells. This blockage led to a sharp decrease in oil production rate and a significant increase in the operating cost. The existing failure analysis procedure was not able to accurately identify the reasons for the blockage; accordingly, the treatment operations were unsuccessful. On the contrary, applying the proposed approach accurately (1) identified the type of the solid deposits, (2) solved the problem using proper treatment option with minimum cost, and (3) improved the oil production rate. The laboratory tests of the fluid and solid deposits showed that (1) the asphaltenes were unstable in the crude oil and acted as a glue for other minerals, and (2) the blockage was successfully diagnosed to confirm that the two wells had asphaltenes precipitation problem. The laboratory tests were extended to select optimum asphaltene dispersant for wells treatments. The field application results showed a significant increase in the oil production rate from 700 to 1600 STB/D in Well-I and from 470 to 1500 STB/D in Well-II. Moreover, the operating cost decreased considerably from 2.01 to 0.43 $/STB in Well-I, and from 4.37 to 0.52 $/STB in Well-II after applying the proposed approach.

Description: Palynofacies is based on the different types of the dispersed/sedimentary organic matter (DOM/SOM) and has been used as a proficient proxy for the palaeoclimatic reconstructions in sedimentary deposits of various time spans. It has also been acknowledged as an effective tool in the different domains like sequence biostratigraphy, palyno-biostratigraphy, palaeodepositional history, identification for depositional processes, oxic–anoxic environment, and variations in the water depth. It has been emerged as an analytical tool in palaeoclimatic reconstruction, which could complement geophysical and geochemical datasets. Since long palynofacies analysis has been exclusively applied in the marine sediments, it has recently dragged the attention of many researchers as a significant parameter for palaeoclimatic interpretation in continental deposits. In the last few decades, more consideration was focused on palynofacies that have become an essential proxy in the biostratigraphic and other non-biostratigraphic fields due to its requirement in the petroleum industries. The present study provides a basic idea of dispersed organic matter characterization, methodology, interpretations, and its application with special emphasis on the Gondwana deposits. The study also includes the summary of the worldwide distribution of the Gondwana sediments, especially for palaeodepositional settings through palynofacies along with other parameters.

Description: The harvest of hydrocarbon from the depleted reservoir is crucial during field development. Therefore, drilling operations in the depleted reservoir faced several problems like partial and total lost circulation. Continuing production without an active water drive or water injection to support reservoir pressure will decrease the pore and fracture pressure. Moreover, this depletion will affect the distribution of stress and change the mud weight window. This study focused on vertical stress, maximum and minimum horizontal stress redistributions in the depleted reservoirs due to decreases in pore pressure and, consequently, the effect on the mud weight window. 1D and 4D robust geomechanical models are built based on all available data in a mature oil field. The 1D model was used to estimate all mechanical rock properties, stress, and pore pressure. The minimum and maximum horizontal stress were determined using the poroelastic horizontal strain model. Furthermore, the mechanical properties were calibrated using drained triaxial and uniaxial compression tests. The pore pressure was tested using modular dynamic tester log MDT. The Mohr–Coulomb model was applied in the 4D model to calculate the stress distribution in the depleted reservoir. According to study wells, the target area has been classified into four main groups in Mishrif reservoir based on depletion: highly, moderately, slightly, and no depleted region. Also, the results showed that the units had been classified into three main categories based on depletion state (from above to low depleted): L1.1, L1.2, and M1. The mean average reduction in minimum horizontal stress magnitude was 322 psi for L1.1, 183.86 psi for L1.2, and 115.56 psi for M1. Thus, the lower limit of fracture pressure dropped to a high value in L1.1, which is considered a weak point. As a result of changing horizontal stress, the mud weight window became narrow.