Waterflooding is a commonly used secondary recovery technique in oil production, where water is injected into a formation to maintain pressure and push oil towards the adjacent production wells. In reservoirs with high permeability contrasts, poor sweep efficiency and a non-uniform displacement front cause large unrecovered hydrocarbon volumes. As the reservoir depletion progresses and the water cut increases, the energy costs and CO2 emission become unfavorable relative to oil production. In 2013, the Norwegian Continental Shelf (NCS) Snorre operators implemented a large-scale sodium silicate injection pilot to divert the reservoir water flow, improve volumetric sweep efficiency, and reduce CO2 emissions. This study utilized a geochemical simulation tool (IORSim) to numerically history match and predict the Snorre water diversion field pilot impact on field performance, reservoir life span, and CO2 footprint. While an industry-standard reservoir simulator was used to compute the velocity fields of the fluid phases (e.g., water, oil, and gas), IORSim calculated the sodium silicate transport, polymerization, and permeability reduction along the temperature front. Instead of simultaneously solving the geochemical reactions in all grid blocks, IORSim identifies upstream and downstream cells to treat chemical species balance as iterative one-dimensional problems. Besides ensuring numerical stability, IORSim allows computation-efficient reactive subsurface modeling using splay tree calculation. In the first IORSim simulation, the injection and production well rates were constrained by the historical field rates to visualize the sodium silicate polymerization along the temperature front and to history-match the injection and production well pressures. The numerical model revealed two phases of gelation: (a) Early near-wellbore gelation due to formation water and silicate slug mixing and (b), in-depth gelation five to ten months after field pilot initialization. The second IORSim model compared the field pilot performance to conventional waterflooding by constraining the injection and production wells by pressure. Between 2013 and 2019, the thief zone plugging lowered the water production by 1.2 MSm3 while the water cut decreased by 2.9%. Moreover, due to the 1.3 MSm3 injection water reduction, the CO2 emissions associated with the water injection pump decreased by 8931 t (34%).

Optimizing the injection water salinity could present a cost-effective strategy for improving oil recovery. Although the literature generally acknowledges that low-salinity improves oil recovery in laboratory-scale experiments, the physical mechanisms behind it are controversial. While most experimental low-salinity studies focus on brine composition, this study investigated the influence of carbonate rock material on surface charge change, wettability alteration, and spontaneous imbibition behavior. Zeta potential measurements showed that each tested carbonate rock material exhibits characteristic surface charge responses when exposed to Formation-water, Seawater, and Diluted-seawater. Moreover, the surface charge change sensitivity to calcium, magnesium, and sulfate ions varied for the tested carbonate materials. Spontaneous imbibition tests led to high oil recovery and, thus, wettability alteration towards water-wet conditions if the carbonate-imbibing brine system's surface charge decreased compared to the initial zeta potential of the carbonate Formation-water system. In the numerical part of the presented study, we find that it is essential to account for the location of the shear plane and thus distinguish between the numerically computed surface charge and experimentally determined zeta potential. The resulting model numerically reproduced the experimentally measured calcium, magnesium, and sulfate ion impacts on zeta potential. The spontaneous imbibition tests were history-matched by linking surface charge change to capillary pressure alteration. As the numerical simulation of the laboratory-scale spontaneous imbibition tests is governed by molecular diffusion (with a time scale of weeks), we conclude that molecular diffusion-driven field scale wettability alteration requires several hundred years.

Reservoir modeling consists of two key components: the reproduction of the historical performance and the prediction of the future reservoir performance. Industry-standard reservoir simulators must run fast on enormous and possibly unstructured grids while yet guaranteeing a reasonable representation of physical and chemical processes. However, computational demands limit simulators in capturing involved physical and geochemical mechanisms, especially when chemical reactions interfere with reservoir flow. This paper presents a mathematical workflow, implemented in IORSim, that makes it possible to add geochemical calculations to porous media flow simulators without access to the source code of the original host simulator. An industry-standard reservoir simulator calculates velocity fields of the fluid phases (e.g., water, oil, and gas), while IORSim calculates the transport and reaction of geochemical components. Depending on the simulation mode, the geochemical solver estimates updated relative and/or capillary pressure curves to modify the global fluid flow. As one of the key innovations of the coupling mechanism, IORSim uses a sorting algorithm to permute the grid cells along flow directions. Instead of solving an over-dimensionalized global matrix calling a Newton–Raphson solver, the geochemical software tool treats the species balance as a set of local nonlinear problems. Moreover, IORSim applies basis swapping and splay tree techniques to accelerate geochemical computations in complex full-field reservoir models. The presented work introduces the mathematical IORSim concept, verifies the chemical species advection, and demonstrates the IORSim computation efficiency. After validating the geochemical solver against reference software, IORSim is used to investigate the impact of seawater injection on the NCS Ekofisk reservoir chemistry.

Evaluation of petrophysical properties such as porosity, permeability, and irreducible water saturation is crucial for reservoir characterization to determine the hydrocarbon initially in place and further optimize hydrocarbon production. However, estimation of these parameters is challenging for carbonate rocks due to their heterogeneity. One of the ways to determine petrophysical properties is the use of nuclear magnetic resonance (NMR), which involves applying a magnetic field to the formation and detecting signals emitted from pore spaces. The main objective of this study is to develop an empirical correlation for porosity, permeability, and irreducible water saturation by comparing NMR and laboratory measurements for carbonate rocks in the Middle East. Furthermore, machine learning (ML) approach was applied to predict these petrophysical parameters utilizing NMR data. Different ML algorithms such as tree-based and neural networks were trained to estimate these petrophysical properties of carbonate rocks. The obtained results from ML algorithms were further compared with core measurements to ensure their accuracy. The results showed that the use of T2 spectrum as an input provided more accurate results than NMR features. It can be proven by observing the performance of deep neural networks algorithm, where the models showed R2 values of 0.87 and 0.74 for porosity prediction using T2 and features extraction approaches, respectively. The same behavior was followed for the permeability estimations as deep neural networks model scored R2 = 0.81 (T2 approach) and R2 = 0.74 (features extraction approach). Similarly, determination of irreducible water saturation was more accurate using T2 approach (R2 = 0.87), whereas features extraction technique also exhibited a decent performance (R2 = 0.71). Also, T2 approach is more convenient since it is more straightforward to generate T2 spectrum from NMR measurements and use it for the ML models. Furthermore, based on the machine learning approach, gradient boosting and deep neural networks models performed with higher accuracy than other algorithms. This can be attributed to their strong configuration, which is able to find patterns between input and output parameters. This study provides more insight into petrophysical properties determined from NMR measurements in carbonates using ML techniques. This is useful in better characterizing carbonate reservoirs in the Middle East through accurate estimations of hydrocarbon resources and related reserves.

Low-salinity waterflooding is a relatively simple and cheap improved oil recovery technique in which the reservoir salinity is optimized to increase oil recovery. Multivalent ion enriched as well as diluted brines have shown promising potential to increase oil production over conventional waterflooding. While the literature generally acknowledges that low-salinity improves oil recovery, the physical mechanisms behind low-salinity effects are still controversial. Surface charge change refers to a low-salinity mechanism in which modified brine is believed to cause a re-equilibrium of the carbonate surface potential. As a result of surface charge change, the rock wettability alters towards a more water-wetting state. This experimental study combines zeta potential, spontaneous imbibition, and contact angle measurements to highlight the effect of carbonate minerals on surface charge change. Initially, zeta potential measurements were conducted to compare the impact of five carbonate minerals (Indiana Limestone, Edward Limestone, Reservoir Limestone, Austin Chalk, and Silurian Dolomite) and brine compositions (Formation-water, Sea-water, and Diluted-sea-water) on carbonate surface charge. Moreover, the impact of potential determining ions (calcium, magnesium, and sulfate) on the mineral surface charge was investigated. The effect of carbonate minerals on spontaneous oil recovery was investigated by comparing the spontaneous imbibition of Formation-water, Sea-water, and Diluted-sea-water into the five carbonate minerals. Moreover, the wettability alteration during the spontaneous imbibition tests was quantified by conducting contact angle measurements. The brine-mineral zeta potential measurements were positive for Formation-water, slightly negative for Sea-water, and strongly negative for Diluted-sea-water. While calcium and magnesium ions promoted stronger positive electrical potentials, sulfate ions caused a zeta potential reduction. The magnitude of surface charge change was significantly different for the five tested carbonate minerals. Under the presence of Diluted-sea-water, the zeta potential measurements of Indiana Limestone and Austin Chalk resulted in strong negative electrical potentials. Reservoir Limestone and Edward Limestone showed less negative zeta potentials, while Silurian Dolomite and Diluted-sea-water resulted in slightly negative zeta potential results. Compared to Formation-water, Sea-water, and particularly Diluted-sea-water caused significant spontaneous oil recovery. The high spontaneous oil recovery of Diluted-sea-water and Indiana Limestone and Austin Chalk correlated with strong negative brine-mineral zeta potentials. Moderate spontaneous oil recovery was observed for the slightly negative zeta potential Sea-water and limestone/chalks systems. The contact angle measurements showed oil-wet contact angles under the presence of Formation-water, while the introduction of Sea-water and Diluted-sea-water promoted stronger water-wet contact angles. This work is one of the very few studies that investigates the effect of carbonate rock mineralogy on surface charge change and spontaneous oil recovery.

Low-salinity waterflooding (LSF) is a relatively simple and cheap Enhanced Oil Recovery technique in which the salinity of the injected water is optimized to improve oil recovery over conventional waterflooding. Sulfate-rich as well as diluted brines have shown promising potential to increase oil production in limestone core samples. To quantify the low-salinity effect, spontaneous imbibition and/or waterflooding experiments have been reported. This paper combines spontaneous imbibition, centrifuge and unsteady state (USS) coreflooding experiments to investigate low-salinity effects in carbonate samples. The experimental study used three brine compositions to investigate low-salinity effects. A high-saline Formation-water (salinity of 183.4 g/l), Sea-water (43.8 g/l) and 100-times Diluted-sea-water (0.4 g/l). Initially, a sequence of spontaneous imbibition experiments was conducted to screen the impact of connate and imbibing water composition on spontaneous oil recovery. After completing the spontaneous imbibition tests, the samples were drained inside a centrifuge to determine the impact of brine composition on residual saturation and capillary pressure. Moreover, three USS corefloodings were conducted to test the different brine compositions in secondary and tertiary injection mode. The spontaneous imbibition, centrifuge method and coreflooding tests showed a consistent trend. Compared to Formation-water and Sea-water, Diluted-sea water demonstrated the most promising potential to recover oil efficiently. The numerical part of the study includes the transparent development of a numerical centrifuge and coreflooding model on the top of the open-source simulator DuMu(x). The mathematical model formulation demonstrates that a simple numerical approach is sufficient to history match the centrifuge and coreflooding experiments. In line with the experimental data, the numerically derived capillary pressure and relative permeability showed an increasing water-wetting behavior as the salinity of the imbibing/injection water decreased. All implemented numerical models were validated against the commercially established Cydar software.

Low salinity water flooding (LSF) is a relatively simple and cheap EOR technique in which the salinit y of the injected water is optimized (by desalination and/or modification) to improve oil recovery over conventional waterflooding. Extensive laboratory experiments investigating the effect of LSF are available in the literature. Sulfate-rich as well as diluted brines have shown promising potential to increase oil production in limestone core samples. To quantify the low salinity effect, spontaneous imbibition and/or tertiary waterflooding experiments have been reported. For the first time in literature, this paper presents a comprehensive study of the centrifuge technique to investigate low salinity effect in carbonate samples. The study is divided into three parts. At first, a comprehensive screening was performed on the impact of different connate water and imbibition brine compositions/combinations on the spontaneous imbibition behavior. Second, the subsequent forced imbibition of the samples using the centrifuge method to investigate the impact of brine compositions on residual saturations and capillary pressure. Finally, three unsteady-state (USS) core floodings were conducted in order to examine the potential of the different brines to increase oil recovery in secondary mode (brine injection at connate water saturation) and tertiary mode (exchange of injection brine at mature recovery stage). The experiments were performed using Indiana limestone outcrops. The main conclusions of the study are spontaneous imbibition experiments only showed oil recovery in case the salinity of the imbibing water (IW) is lower than the salinity of the connate water (CW). No oil production was observed when the imbibing water had a higher salinity than the connate water or the salinity of the connate water and imbibing brine were identical. Moreover, the spontaneous imbibition experiments indicated that diluting the salinity of the imbibing water has a larger potential to spontaneously recover oil than the introduction of sulfate-rich sea water. The centrifuge experiments confirmed a connection between the overall salinity and oil recovery. As the salinity of the imbibing brines decreases, the capillary imbibition pressure curves showed an increasing water-wetting tendency and simultaneous reduction of the remaining oil saturation. The lowest remaining oil saturation was obtained for diluted sea water as CW and IW. The core flooding experiments reflected the results of the spontaneous imbibition and centrifuge experiments. Injecting brine at a rate of 0.05 cc/min, sea water and especially diluted sea water resulted in a significant higher oil recovery compared to formation brine. Moreover, when comparing secondary mode experiments, the remaining oil saturation after flooding by diluted sea water, sea water and formation water was 30.6 %, 35.5 % and 37.4 %, respectively. In tertiary injection mode, sea water did not lead to extra oil recovery while diluted sea water led to an additional oil recovery of 5.6 % in one out of two tertiary injection applications.

Low-salinity waterflooding is a relatively simple and cheap Enhanced oil recovery technique in which the salinity of the injected water is optimized (by desalination and/or modification) to improve oil recovery over conventional waterflooding. The presented study combines spontaneous imbibition, centrifuge method, unsteady state coreflooding and zeta potential experiments to investigate low-salinity effects in carbonate limestones samples. Compared to Formation-water and Sea-water, Diluted-sea-water caused the significantly highest spontaneous oil recovery. Moreover, the imbibition capillary pressure curves are characterized by an increasing water-wetting tendency and a residual oil saturation reduction, as the salinity of the imbibing brines decreases in comparison to Formation-water. The unsteady state corefloodings resulted in the highest secondary oil recovery when Diluted-sea-water was used as injection water. Based on the open-source C++ simulator Dumux, the study developed a numerical centrifuge and coreflooding model to history match the experimental data. The numerically derived capillary pressure and relative permeability data confirm a correlation between the system’s salinity, wettability, oil recovery and residual oil saturation.%%%%Low-salinity Wasserfluten ist eine simple und kostengunstige Technik zur verbesserten Olgewinnung, bei der der Salzgehalt des eingepressten Wassers (durch Entsalzung und/oder Modifikation) optimiert wird. In der Fachliteratur sind experimentelle Studien verfugbar, in denen sulfatreiches als auch entsalztes Wasser ein vielversprechendes Potenzial zur Steigerung der Olproduktion aus Kalksteinproben gezeigt haben. Diese Dissertation kombiniert erstmalig Spontaneous-imbibition, Zentrifugen und Kernflutungsexperimente zur Untersuchung von Low-salinity Effekten in Kalksteinproben. Daruber hinaus wurden Zeta-Potential Messungen durchgefuhrt, um das Konzept der Oberflachenladungsveranderung als moglichen Mechanismus von Low-salinity Effekten in Kalksteinen zu untersuchen. In der experimentellen Studie wurden drei Injektionswasserzusammensetzungen getestet: Ein hochsalzhaltiges Formationswasser (Salzgehalt von 183,4 g/l), ein sulfatreiches Meerwasser (Salzgehalt von 43,8 g/l) und 100-fach verdunntes Meerwasser (Salzgehalt von 0,44 g/l). Die Spontaneous-imbibition Tests zeigten nur dann Olproduktion, wenn der Salzgehalt des eindringenden Wassers niedriger war als der Salzgehalt des initialen Wassers. Es wurde keine Olproduktion beobachtet, wenn das eindringende Wasser einen hoheren Salzgehalt als das initiale Wasser aufwies oder der Salzgehalt der beiden Fluide identisch war. Die Spontaneous-imbibition Tests ergaben eine Olgewinnung von 35,4% fur 100-fach verdunntes Meerwasser, 22,1 % fur Meerwasser und 1,5 % fur Formationswasser. Die Zentrifugenversuche bestatigten eine Verbindung zwischen Salzgehalt und Olgewinnung. Mit abnehmendem Salzgehalt zeigten die Kapillardruckkurven eine zunehmende Wasserbenetzungstendenz und eine gleichzeitige Verringerung der Restolsattigung. Die…