Clay minerals damage quantification in sandstone rocks using core flooding and NMR

Sandstone oil reservoirs consist of different clay minerals such as kaolinite, illite, and chlorite. These clay minerals highly affect the formation damage during enhanced oil recovery (EOR) and well stimulation operations in these reservoirs. No attention was paid to investigate the effect of these clay minerals on the formation damage during different reservoir processes. In addition, no solution was introduced to mitigate the effect of clay minerals on the formation damage in sandstone reservoirs. In this study, the effect of clay mineral contents and type on the formation damage was studied in detail by injecting water and HCl as damaging fluids. Bandera grey, Berea, and Bandera brown sandstone rocks with various clay mineral contents were studied. XRD was used to characterize the sandstone rocks to determine the clay type and content in each rock. Two core plugs from each rock were selected for HCl and water injection. Core flooding experiments were performed to measure the initial and final permeability. In the core flooding experiments, fluids were injected into the cores at 25 °C and at a backpressure of 1000 psi. SEM was carried out before and after flooding for the tested rocks to locate the change in the clay distribution inside the rocks. The NMR analysis of core samples was done before and after flooding with the damaging fluid to quantify the formation damage and to find the possible damaging mechanism. NMR was used to locate the damage inside the rock due to the migration of clay minerals. Based on the core flooding, SEM, and NMR analysis, the maximum damage by the fresh water took place in Berea sandstone core due to fine migration and clay swelling. The illite clay mineral and chlorite can cause the formation damage on HCl injection. Illite can break down and migrates in the cores during the acid injection. In sandstone acidizing, chlorite clay mineral caused iron hydroxide precipitation inside the cores during treatment with mud acid. NMR showed that clay minerals plugged the pore throats of the rocks and reduced the rock permeability during the injection of fresh water

Prevention of barite sag in water-based drilling fluids by a urea-based additive for drilling deep formations

Barite sag is a challenging phenomenon encountered in deep drilling with barite-weighted fluids and associated with fluid stability. It can take place in vertical and directional wells, whether in dynamic or static conditions. In this study, an anti-sagging urea-based additive was evaluated to enhance fluid stability and prevent solids sag in water-based fluids to be used in drilling, completion, and workover operations. A barite-weighted drilling fluid, with a density of 15 ppg, was used with the main drilling fluid additives. The ratio of the urea-based additive was varied in the range 0.25–3.0 vol.% of the total base fluid. The impact of this anti-sagging agent on the sag tendency was evaluated at 250 °F using vertical and inclined sag tests. The optimum concentration of the anti-sagging agent was determined for both vertical and inclined wells. The effect of the urea-additive on the drilling fluid rheology was investigated at low and high temperatures (80 °F and 250 °F). Furthermore, the impact of the urea-additive on the filtration performance of the drilling fluid was studied at 250 °F. Adding the urea-additive to the drilling fluid improved the stability of the drilling fluid, as indicated by a reduction in the sag factor. The optimum concentration of this additive was found to be 0.5–1.0 vol.% of the base fluid. This concentration was enough to prevent barite sag in both vertical and inclined conditions at 250 °F, with a sag factor of around 0.5. For the optimum concentration, the yield point and gel strength (after 10 s) were improved by around 50% and 45%, respectively, while both the plastic viscosity and gel strength (after 10 min) were maintained at the desired levels. Moreover, the anti-sagging agent has no impact on drilling fluid density, pH, or filtration performanceThis research received no external funding. The authors wish to acknowledge King Fahd University of Petroleum and Minerals (KFUPM) for allowing them to utilize various facilities in carrying out this research. Many thanks are due to the anonymous referees for their detailed and helpful comments.Scopu

In vitro haemodynamic and computer aided design of an artificial coronary arteries

Abstract not available

Effect of CO2 content on the natural gas production from tight gas sandstone reservoirs

The simulation of the gas flow in tight sandstone reservoir is a very complicated process. Several mechanisms contributed to the natural gas production in tight sandstone reservoirs. One of the main mechanisms is the gas desorption from the rock surface to the pore body. All the existing models did not consider the effect of CO2 content in the natural gas on the gas desorption from the rock surface. Also all the existing models used desorption models from the literature and they neglect the effect of rock type and reservoir conditions on the gas desorption behavior. In this study and for the first time we will investigate the effect of CO2 content (0 to 20 vol%) on the natural gas desorption from the tight sandstone rocks. Accurate desorption isotherm will be developed based on the rock type and gas composition. Adsorption/desorption experiments will be carried out at different pressures and temperatures to develop a robust model for the natural gas desorption from the rock. Also the effect of tight sandstone rock mineralogy was investigated on the adsorption/desorption of the natural gas. Increasing CO2 fraction in the mixture from 0% to 10% CO2 the total gas uptake is increased to approximately 28%, 22% and 33% at 50 C, 100 C and 150 C respectively which reflects the high affinity toward CO2 from the tight sandstone core. The tight sandstone mineralogy also affected the desorption behavior of the natural gas. The presence of water bearing clay minerals such as illite exhibited a vast sensitivity to temperature causing damage to crystal structure and expulsion of bounded water which resulted in huge increase in the adsorption uptake. The results of the experimental studies showed that the CO2 content in the natural gas has a big effect on the desorption of the natural gas from the tight sandstone rocks. The CO2 content also affected the desorption isotherm model for the natural gas. The tight sandstone mineralogy also affected the desorption behavior of the natural gas. The output from this study is a robust model that explain the contribution of the desorption of the natural gas to the total gas production. Also, it will enhance the simulation and flow models that describe the flow of natural gas in porous media in tight sandstone reservoirs.Scopu

Effect of CO2 adsorption on enhanced natural gas recovery and sequestration in carbonate reservoirs

In this study, CO2 injection for the purpose of Enhanced Gas Recovery (EGR) and sequestration after primary recovery is investigated on Pink Desert limestone from Edwards Plateau formation in central-west Texas. In this paper, competitive adsorption of CH4 and CO2 is studied in the temperature range 50 ?C?150 ?C using a mixture of CO2 and CH4. Methane adsorption on the surface of the carbonate rock reduced from 50 mg/g at 50 ?C to 12.4 mg/g at 150 ?C due to exothermic nature of physical adsorption of methane on calcite. Addition of 10% CO2 to methane has enhanced the adsorption from 12.4 mg/g for pure methane to 18.3 mg/g for the 10% CO2 gas mixture at 150 ?C. Adding CO2 to methane will compete with CH4 on the adsorption sites and due to CO2 high adsorption affinity the total uptake of the system is increased depending on CO2 partial pressure. The adsorption experiments have shown that the adsorption of CO2 on Pink Desert limestone is four times higher than that of CH4 at the same pressure and temperature due to the high affinity of CO2 to the calcite rocks derived from strong electrostatic attraction between CO2 molecules and calcite. The thermodynamic analysis confirmed the high natural selectivity of carbonate toward CO2 with lower heat of adsorption for CO2 and the adsorption is spontaneous at low temperatures. The adsorption-desorption experiments showed that CO2 content of injected gas has a strong influence on natural gas desorption from the rocks. The CO2 content and rock mineralogy influence the desorption isotherm model. The potential of using CO2 in EGR and sequestration applications especially in low temperature reservoirs is discussed. A model that explains the contribution of the desorption of natural gas to the total gas production is proposed. ? 2017 Elsevier B.V.The authors would like to acknowledge the support provided by King Abdulaziz City for Science and Technology (KACST) through the Science & Technology Unit at King Fahd University of Petroleum & Minerals (KFUPM) for funding this work through project No. 11-ADV2131-04 as part of the National Science, Technology and Innovation Plan. In addition, KFUPM is also acknowledged

Numerical analysis and experimental validation of high pressure gas quenching

Aided by the computational fluid dynamics package CFX-4 a transient flow model has been used to simulate the process of high pressure gas quenching of a large H13 die. The predicted temperature distributions, obtained under steady and transient flow conditions, together with experimental data have been compared, and a good agreement was obtained. This suggests that a steady state simulation can be effectively used in this type of study to achieve accurate simulated data with reduced computational time. This series of studies is seen as the precursor to the development of an overall simulation procedure for simultaneous distortion and heat transfer characterisation of the die leading to optimum heat treatment control