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Resistivity logging is an important branch of well logging. Essentially, it is the recording, in uncased (or, recently, even cased) sections of a borehole, of the resistivities (or their reciprocals, the conductivities) of the subsurface formations, generally along with the spontaneous potentials (SPs) generated in the borehole. This recording is of immediate value for geological correlation of the strata and detection and quantitative evaluation of possibly productive horizons. The information derived from the logs may be supplemented by cores (whole core or sidewall samples of the formations taken from the wall of the hole). Several types of resistivity measuring systems are used that have been designed to obtain the greatest possible information under diverse conditions (see links below).
The formation water density is defined as the mass of the formation water per unit volume of the formation water. Density is determined most accurately in the laboratory on a representative sample of formation water. . Electronic densiometers can quickly determine the density with accuracy of / 0.00001 g/cm3 over a wide range of temperatures, although most oilfield data are reported at a 60 F reference temperature. In the past, density in metric units (g/cm3) was considered equal to specific gravity; therefore, for most engineering calculations, density and specific gravity were interchangeable in most of the older designs. However, process simulation software used in modern facility design uses the true density or specific gravity of the water to avoid significant cumulative errors, especially when working with low-gravity heavy oils or concentrated brines.
Even with a properly designed single well chemical tracer (SWCT) test, interpreting the data requires judgment calls, and typically, simulation, to arrive at a final estimation of residual oil. Tomich et al. report one of the earliest SWCT tests, which was performed on a Frio Sandstone reservoir on the Texas Gulf Coast. The results of this test are used here to demonstrate the details of SWCT test interpretation for an ideal situation. The test well in the Tomich et al. report was in a fault block that had been depleted for several years. Because of the natural water drive and high permeability of the sand, the formation was believed to be near true Sor.
The SP curve is a continuous recording vs. depth of the electrical potential difference between a movable electrode in the borehole and a surface electrode. Adjacent to shales, SP readings usually define a straight line known as the shale baseline. Next to permeable formations, the curve departs from the shale baseline; in thick permeable beds, these excursions reach a constant departure from the shale baseline, defining the "sand line." The deflection may be either to the left (negative) or to the right (positive), depending on the relative salinities of the formation water and the mud filtrate. If the formation-water salinity is greater than the mud-filtrate salinity (the more common case), the deflection is to the left.
Resistivity logging is an important branch of well logging. Essentially, it is the recording, in uncased (or, recently, even cased) sections of a borehole, of the resistivities (or their reciprocals, the conductivities) of the subsurface formations, generally along with the spontaneous potentials (SPs) generated in the borehole. This recording is of immediate value for geological correlation of the strata and detection and quantitative evaluation of possibly productive horizons. The information derived from the logs may be supplemented by cores (whole core or sidewall samples of the formations taken from the wall of the hole). As will be explained later, several types of resistivity measuring systems are used that have been designed to obtain the greatest possible information under diverse conditions (e.g., induction devices, laterolog, microresistivity devices, and borehole-imaging devices).
A number of cementitious materials used for cementing wells do not fall into any specific API or ASTM classification.These materials include: Pozzolanic materials include any natural or industrial siliceous or silico-aluminous material, which will combine with lime in the presence of water at ordinary temperatures to produce strength-developing insoluble compounds similar to those formed from hydration of Portland cement. Typically, pozzolanic material is categorized as natural or artificial, and can be either processed or unprocessed. The most common sources of natural pozzolanic materials are volcanic materials and diatomaceous earth (DE). Artificial pozzolanic materials are produced by partially calcining natural materials such as clays, shales, and certain siliceous rocks, or are more usually obtained as an industrial byproduct. Pozzolanic oilwell cements are typically used to produce lightweight slurries.
Summary It is common to produce some percentage of water during the oil‐extraction process. Conventionally, some water‐disposal wells are drilled in an oil field to inject these useless and hazardous waters. Mineral scale formation is a critical issue in water‐injection wells and may result in well plugging and an injection rate decrease in these wells. The two steps of mineral scale formation are scale precipitation and scale deposition. Two main mechanisms of inorganic scale precipitation are incompatibility between injected water and reservoir formation water and changes in the thermodynamic state of injected water. The injectivity of the well decreases because of deposition of supersaturated precipitated scales through the well column and near‐wellbore region. Currently, limited research has been done to evaluate inorganic scale deposition, and most of the research is limited to calculation of total scaling by commercial software. In this study, the mineral scale precipitation is evaluated by software modeling and laboratory experiments in an Iranian oil field, and the effect of the scale deposition phenomenon is assessed on permeability impairment and injection rate decrease. One of the major novelties of this work is simulation of various scale‐deposition models by coupling MATLAB® software coding and a reservoir simulator. The accuracy of different deposition models is analyzed by comparing them with field data (real water‐injection well) and laboratory tests (coreflooding test). Finally, our simulation results show that a single deposition model could not exactly predict the scaling phenomena in the studied carbonate reservoir that is supersaturated with CaCO3 and CaSO4. It is recommended to improve the scale‐formation prediction with a mixed deposition model supported by reliable static/dynamic modeling and experimental analysis.
Summary Seawater injection is widely used to improve oil recovery in offshore oil reservoirs. However, injecting seawater into reservoirs can cause many flow-assurance issues, such as scaling and reservoir souring, which are strongly related to the percentage of seawater breakthrough. Thermodynamic models have been developed to evaluate the effects of barite deposition on oil production, but the reservoir stripping effect has not been fully considered. In this study, a new model that incorporates both chemical reaction (barium and sulfate reaction) and physical reactions (ion adsorption/desorption) is developed to investigate the in-situbarite-deposition process. To the best of our knowledge, for the first time, ion adsorption/desorption is integrated by coupling the adsorption/desorption isotherm to the reservoir simulator. The barium and sulfate chemical reaction is modeled by incorporating the solubility product constant into the model. The model accuracy is verified through convergence rate tests and comparison with the coreflood experimental results. The simulation results of both barium and sulfate concentration profiles are greatly improved by integrating the ion adsorption/desorption process. The new physicochemical model is further used to investigate barite deposition under various scenarios. Simulation results indicate that most barite deposits are in the deep reservoir for the areal model. Barite that deposits in the reservoir before seawater breakthrough accounts for 45% of total barite deposition and the barite deposited during the seawater-breakthrough period makes up 54%, while the deposition during the tailing period, where the seawater fraction is larger than 95%, is negligible. For a homogeneous reservoir, the barite-deposition period at the near-wellbore area of the producer is between 30% and 65% of the seawater-breakthrough percentage, and heterogeneity leads to a broader deposition period. For vertical heterogeneous reservoirs, a considerable amount of barite forms in the wellbore, which accounts for 17% of total barite deposition. Based on the accurate simulation of barium and sulfate transport in the reservoir, barium and sulfate concentration profiles can be used to determine the seawater-breakthrough percentage and help optimize production operations that aim to mitigate flow assuranceissues.
Abstract Low salinity waterflooding has been an area of great interest for researchers for almost over three decades for its perceived "simplicity," cost-effectiveness, and the potential benefits it offers over the other enhanced oil recovery (EOR) techniques. There have been numerous laboratory studies to study the effect of injection water salinity on oil recovery, but there are only a few cases reported worldwide where low salinity water flooding (LSW) has been implemented on a field scale. In this paper, we have summarized the results of our analyses for some of those successful field cases for both sandstone and carbonate reservoirs. Most field cases of LSW worldwide are in sandstone reservoirs. Although there have been a lot of experimental studies on the effect of water salinity on recovery in carbonate reservoirs, only a few cases of field-scale implementation have been reported for the LSW in carbonate reservoirs. The incremental improvement expected from the LSW depends on various factors like the brine composition (injection and formation water), oil composition, pressure, temperature, and rock mineralogy. Therefore, all these factors should be considered, together with some specially designed fit-for-purpose experimental studies need to be performed before implementing the LSW on a field scale. The evidence of the positive effect of LSW at the field scale has mostly been observed from near well-bore well tests and inter-well tests. However, there are a few cases such Powder River Basin in the USA and Bastrykskoye field in Russia, where the operators had unintentionally injected less saline water in the past and were pleasantly surprised when the analyses of the historical data seemed to attribute the enhanced oil recovery due to the lower salinity of the injected water. We have critically analyzed all the major field cases of LSW. Our paper highlights some of the key factors that worked well in the field, which showed a positive impact of LSW and a comparative assessment of the incremental recovery realized from the reservoir visa-a-vis the expectations generated from the laboratory-based experimental studies. It is envisaged that such a comparison could be more meaningful and reliable. Also, it identifies the likely uncertainties (and their sources) associated during the field implementation of LSW.
Abstract The use of LSWF (Low Salinity Water Flooding) is becoming more prevalent in recent years which can both improve the recovery factor and reduce the cost compared to other EOR (enhanced oil recovery) technics. This is especially important for the offshore oilfield development at present. Moreover, good quality of injected water is more applicable to low permeability sand which is characterized as smaller pore-throat radius and is easier damaged. Therefore, LSWF technology is proposed to address the above production problem while reduce the investment of equipment upgrade. In this paper, we presented the optimization and implementation of LSWF for offshore low permeability reservoir. Firstly, we provided a critical review of LSWF included the main mechanisms, laboratory test and field effect. Secondly, we designed and conducted several laboratory core flood tests. Thirdly, a lot of synthetic models were established to simulate the effects of LSWF and to optimize the field program. Finally, the production performance of the pilot wells was discussed. After LSWF, the water injection well presents the phenomenon of "scissors" - the injection pressure drops significantly below the safety pressure while the injection volume increases. Moreover, the decline of pilot well groups decreased by 20% ~ 26% compared with non-water flooded. The estimated recovery factor increased by 12%, which is consistent with other field tests worldwide. In summary, LSWF is a feasible, neconomic and efficient method for offshore low permeability reservoir production.