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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.
Abstract Acidizing is the most commonly used method to stimulate carbonate reservoirs. To achieve a better assessment of the operation, a flowback analysis is conducted. Flowback analysis can give insights on the reservoir's response to the recipe. This analysis can be used to improve future treatment operations where some recommendations were deduced. The objective of this paper was to show the flowback analysis methodology following carbonate acidizing treatments with a focus on dissolved elements. X-ray diffraction (XRD), X-ray fluorescence (XRF), environmental scanning electron microscope (ESEM), and inductive coupled plasma (ICP) were used to determine the composition of flowback fluids and the filtered precipitate. Combining the data from different techniques onsite and in laboratory assess the development of a methodology for calculating more accurate amounts of dissolved elements, formation water, and volumes of recovered fluids. This analysis showed acid recipes efficiency of nearly 100% based dissolved calcite. Around 65% of injected fluids were lost into a formation. The iron concentration during the flowback was 1400 ppm, however, cumulative amount of iron in flow back samples was below expected value. Based on the formation's rock analysis, the theoretical amount of iron in the recovered flowback fluid was 1000 kg. The measured amount of iron was 500 kg and the rest could be assumed to be precipitated in a reservoir. This study helps in understanding the flowback fluid analysis and its importance by using a step-by-step analysis procedure for flowback fluid samples from the carbonate acidizing operations. The results of this study help in tracking the elements that potentially help in estimating the lost fluids volumes and percentage of success for a carbonate reservoir acid operation.
Hassan, Anas. M. (Universiti Teknologi PETRONAS) | Ayoub, Mohammed (Universiti Teknologi PETRONAS) | Eissa, Mysara (Universiti Teknologi PETRONAS) | Bruining, Hans (Delft University of Technology) | Al-Mansour, Abdullah (King Abdulaziz City for Science and Technology) | Al-Quraishi, Abdulrahman (King Abdulaziz City for Science and Technology)
Abstract Given the increasing demand for energy globally and depleting oil and gas resources, it is crucial to increase the production from existing reservoirs by introducing new technologies for Improved/Enhanced Oil Recovery (IOR/EOR). This contribution presents a novel hybrid IOR/EOR method, which combines smart water (SW) and foam flooding, known as Smart Water Assisted Foam (SWAF) flooding. The optimal conditions of the SWAF technology will be interpreted using experimental laboratory design (i.e., experimental data). The experimental design was divided into three main steps. The first step is obtaining rock wettability measurements using contact angle measurements. This step aims to select the optimum SW composition that changes the carbonate rock's wettability from oil-wet towards more water-wet and faster oil recoveries. The water-wet condition leads to high residual oil saturations and low end-point permeabilities. This is conductive to favourable mobility ratios and efficient water-oil displacement. However, high residual oil saturations are unfavourable to the high ultimate oil recovery as much oil stays behind. Secondly, the chemical screening follows, where two tests were performed, viz., (i) an Aqueous Stability Test (AST), (ii) and a Foamability and Foam Stability Tests (FT/FST). This step aims to generate a stable foam (i.e., surfactant aqueous solution + gas) in the absence and presence of crude oil with different TAN (Total Acid Number) and TBN (Total Base Number), viz., crude oils Type-A and Type-B. Favourable mobility ratio is achieved by the presence of foam, which leads to excellent displacement efficiency. Thirdly, core flooding tests are performed. This step aims to select the best formulations through SWAF core flooding tests to obtain the ultimate recovery factor under different injection scenarios. The optimal SWAF condition combines high ultimate recovery with the best displacement efficiency. It is shown that the enormous changes in wettability were seen for SW (MgCl2) solution at 3500 (ppm) for both crude oils Type-A and Type-B. It has been shown that the use of a cationic surfactant CTAB (i.e., cetyltrimethylammonium-bromide) in the positively charged carbonates (with an isoelectric point of pH = 9) is more effective than the use of anionic surfactant, e.g., Alpha Olefin Sulfonate (AOS). The aim is to create an optimum surfactant aqueous solution (SAS). The SAS stability is considerably affected by the concentration of both the SW (MgCl2) and surfactant (CTAB). In the absence of oil, the strength of foam (SAS and Gas) is highly dependent on the concentration and composition of the SW in the SAS. In the presence of oil, foam generation and stability are better when the crude oil has a low TAN and high TBN. From the core flooding tests for crude oils Type-A and Type-B, the ultimate residual oil recovery was achieved by the MgCl2 - foam injection combination (i.e., incremental oil recovery of 42%, which is equivalent to a cumulative oil recovery of 92%). In summary, SWAF under the optimum conditions is a promising method to increase the oil recovery from carbonate reservoirs.
Using the single well chemical tracer (SWCT) test avoids the problems of too-wide well spacing and excessive tracer dispersion caused by layering that can occur with well to well tests. In the SWCT test, the tracer-bearing fluid is injected into the formation through the test well and then produced back to the surface through the same well. The time required to produce the tracers back can be controlled by controlling the injected volume on the basis of available production flow rate from the test well. In a single-well test, tracers injected into a higher-permeability layer will be pushed farther away from the well than those in a lower-permeability layer, as indicated in Figure 1a; however, the tracers in the higher-permeability layer will have a longer distance to travel when flow is reversed. As the tracer profiles in Figure 1b show, the tracers from different layers will return to the test well at the same time, assuming that the flow is reversible in the various layers.
The focus in unconventional exploration and production is shifting to maximizing production. "The next big play is getting more out of what you have," said Jay Ottoson, president and chief operating officer for SM Energy, at the recent Unconventional Resources Technology Conference in Denver. Adding one percentage point to recoveries from the top unconventional formations for oil and gas in the United States will add billions of billions of barrels of oil production and tens of trillions of cubic feet of gas, he said. There is plenty of room for improvement. The examples offered by Ottoson would increase the ultimate recovery rate in the biggest US oil plays from 5% to 6%. Comments by others during the conference, a joint project of SPE, AAPG, and SEG, indicated that range is not uncommon as companies look for ways to do better. Even at those levels, the growing flow of oil and gas from these extensive formations has pushed the US up toward the top of the list of the world's producers.