Alkhazmi, Bashir (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Farzaneh, Seyed Amir (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Sohrabi, Mehran (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University)
A Water-alternating-gas (WAG) injection is a broadly practised technique in oil fields. Gas viscosity is a significant parameter that can affect the efficiency of gas and WAG injections. By conducting the current coreflood experiments at reservoir conditions, we aimed to investigate the effect of gas viscosity on gas and WAG injection performance in terms of oil recovery and differential pressure.
Both WAG injection experiments were performed on the same Clashach sandstone core, under weakly water-wet and near miscible (gas/oil IFT = 0.04 mN.m-1) conditions, using two different hydrocarbon systems (C1-nC4 and C1-nC10). To eliminate the impact of the experimental artifact, a long and large core (2ft x 2 in) was employed. In addition, after each initial water injection, water was pumped through the core at multi-rates, for further investigation of the impact of capillary end effects on our experimental results. To facilitate the interpretation of the data and the comparison, the same injection strategy and methodology were followed in both coreflood experiments. In each injection scenario, four water slugs, starting with primary water flooding, were injected in an alternating manner with four gas cycles.
The results of these WAG experiments showed that the cyclic oil recovery performance during different water and gas injection cycles increased as the number of WAG slugs increased. Investigating the effect of gas viscosity on the performance of oil recovery during gas and WAG injections revealed higher oil recovery performance during the tertiary (three-phase displacement) water injection cycles that were subsequent to the preliminary water flood periods, in WAG injection with C1-nC4 than that in C1-nC10. In contrast, the efficiency of oil recovery during the successive gas injection cycles (under three-phase conditions) was lower in C1-nC4 than that in C1-nC10. The ultimate oil recovery achieved by WAG injection under weakly water-wet and near miscible conditions reached 93 % and 94.5 % (IOIP %) in C1-nC4 and C1-nC10 respectively. On the other hand, the results showed also an extra oil quantity of 3.7 % (Sor%) recovered during the alternation of water and gas injections post-waterflood, by C1-nC10 compared with that in C1-nC4. Studying the impact of the gas viscosity on the injectivity showed a significant drop in the periodic gas injectivity, during different gas injection cycles in WAG injection for C1-nC10 compared with its values for C1-nC4.
A comprehensive series of data sets, generated for two WAG injection experiments with different hydrocarbon fluids (C1-nC4 and C1-nC10) will be reported in this paper. WAG injection is a special case that involves complex multi-phase and multi-physics processes, which are well-known to be difficult to reliably predict by the current existing reservoir simulators. Therefore, representative and reliable experimental data are needed to improve our understanding of the complex underlying mechanisms of oil recovery by WAG injection and to develop improved models and methodologies for reliable predictions of the performance of WAG injection under reservoir conditions.
Africa (Sub-Sahara) Petroceltic International said that the first of up to 24 new development wells planned in Algeria's Ain Tsila gas and condensate field was successful. The AT-10 well, situated about 2 miles from the AT-1 field discovery well, reached a total depth of 6,578 ft. Wireline logs indicated that the expected initial offtake rate would be comparable to the AT-1 and AT-8 wells, both of which test-flowed at more than 30 MMcf/D. Petroceltic is the operator with a 38.25% interest in the production-sharing contract that covers the Ain Tsila output. The remaining interests are held by Sonatrach (43.375%) and Enel (18.375%). Sonangol reported that it has found reserves in the Kwanza Basin of Angola that could total 2.2 billion BOE, including reserves in a block jointly owned with BP. Block 24, operated by BP, holds an estimated 280 million bbl of condensate and 8 Tcf of gas, totaling 1.7 billion BOE, Sonangol said in a statement seen by Reuters.
We suggest two new thermodynamic models for the adsorption of ions to the brine/carbonate and brine/crude oil interface. We calibrate the model parameters to the ionic adsorption and zeta potential data. We then investigate the effect of the rock and oil surface charges on the dissolution, wettability alteration, and mechanical properties of the carbonates in the context of modified-salinity water flooding in the North Sea chalk reservoirs.
We modify a charge-distribution multi-site complexation (CD-MUSIC) model and optimize its parameters by fitting the model to a large data set of calcite surface zeta potential in presence of different brine compositions. We also modify and optimize a diffuse layer model for the oil/brine interface. We then use the optimized surface complexation models with a finite-volume solver to model the two phase reactive transport of oil and brine in a chalk reservoir, including the impact of dissolution, polar-group adsorption, and compaction on the relative permeability of chalk to water and oil. We compare the simulation results with the published experimental data.
Taheri, Mirhossein (Danish Hydrocarbon Research and Technology Center) | Bonto, Maria (Danish Hydrocarbon Research and Technology Center) | Eftekhari, Ali Akbar (Danish Hydrocarbon Research and Technology Center) | M. Nick, Hamidreza (Danish Hydrocarbon Research and Technology Center)
Our objective is to find an alternative approach to the history matching of the modified salinity water flooding tests in secondary and tertiary mode. Instead of matching only the recovery factor and pressure drop history, we give a higher priority to matching the different ion concentrations and oil breakthrough times. Based on these analyses, we suggest the predominant mechanisms for the modified-salinity water flooding in carbonates.
The work is done in three steps: 1) Studying a large data-set of modified-salinity water flooding experiments in carbonates. 2) Quantifying the adsorption of potential determining ions (PDIs) on the carbonate surface using an optimized in-house surface-complexation model 3) Adjusting the relative permeability parameters to history-match the experimental data using different analytical solution of water-flooding (with and without ionic adsorption) combined with modern search-based optimization algorithms. The optimization algorithm gives a high weight factor to the breakthrough time of oil and PDIs.
Having too many parameters in the relative permeability (6 parameters for Brooks-Corey type) make it possible to match any type of recovery curves. However, we found out that matching the breakthrough times, especially in the tertiary modified salinity waterflooding, can only be achieved by considering the wettability change due to the adsorption of PDIs on the carbonate surface. This observation, combined with our ability to accurately model the adsorption of PDIs on the carbonate surface, helped us to identify the important PDIs that cause the wettability change in carbonates. For instance, we observe that a model that considers the wettability change due to the adsorption of calcium ions on the chalks surface matches perfectly to the tertiary flooding of the Stevns Klint outcrop chalk with seawater. The second important observation is that the lag between the start of the injection of the modified-salinity brine and the oil breakthrough time is not always due to the adsorption of ions and sometimes can be explained by the wettability change due to the lower salinity of the injected brine. It must be noted that this new approach is still semi-empirical, and needs to be combined with more fundamental studies to identify the actual mechanisms.
Alhuraishawy, Ali K. (Missan Oil Company / Reservoir and Fields Development Directorate) | Bai, Baojun (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Al-Bazzaz, Waleed H. (Kuwait Institute for Sciencefic Research)
One of the EOR technologies is low-salinity water flooding (LSWF) is an EOR method that operates at a lower cost than other EOR methods, which makes it a preferred area of interest for oil industry economists, who continue to call for EOR costs to come down. The aim is to minimize the possible cost to recover as much oil as possible. The performance of low salinity waterflooding in decreasing residual oil saturation in low permeability- porosity clay-rich sandstone reservoir.
Porosity test, core flooding test, XRD and scanning electron microscopy (SEM) tests were achived in this study. Salinity effect on the porosity, oil recovery, and injecton pressure was established. The results showed that low salinity waterflooding resulted in improving oil recovery and porosity with permeability reduction and decreased the clay content. SEM results results showed that the flowing direction will be restributed during low salinity waterflooding by realizing some sand particle and minerals and increased the porosity. Therefore, low salinity water flooding can modify both porosity and permeability and, in turn, improve oil recovery factor.
The objective of this paper is to describe experiments conducted to investigate osmosis as a mechanism for low-salinity enhanced oil recovery (EOR). For this purpose, an experiment was designed to facilitate enhanced oil recovery by osmosis-induced connate water expansion, while at the same time reducing the contributions of other proposed low-salinity mechanisms. Considerations were also made to achieve osmotic water transport rates comparable to what is expected at reservoir temperature.
The correlation between enhanced oil recovery and the surface-to-volume ratio was of particular interest. Because the osmotic pressure gradients occur over distances comparable to the pore size, it is plausible that fluid redistribution due to osmosis would lead to a fairly local redistribution of oil, and thereby have a small impact on overall enhanced recovery in the field. However, near exposed surfaces, this local redistribution may result in oil production.
Previous investigations of osmosis as an underlying low-salinity mechanism have consisted of visualization experiments, where water transport and oil movement under influence of osmotic gradients have been observed. Our experiments are intended to increase the understanding of the relative importance of osmosis in both small-scale low-salinity experiment results, and for field-scale low-salinity flooding.
In the experiments, oil-wet sandstone samples with different surface-to-volume ratios were saturated with high-salinity water and oil to irreducible water saturation. The samples were first left to spontaneous imbibe in high-salinity water and afterward in low-salinity water. Additional oil production from spontaneous imbibition of low-salinity was recorded and compared with the surface-to-volume ratio. The experiment was performed twice, at both ambient and elevated temperatures.
The experiments at ambient temperature resulted in increased oil production values of 8-22% of pore volume by low-salinity spontaneous imbibition. No clear correlation was found between increased oil recovery and the surface-to-volume ratio. A correlation was, however, seen between increased oil production and the pore volume. Thus, increased oil production by low-salinity imbibition seems to be proportionate to the pore volume.
The experiments at elevated temperature resulted in low values of increased oil production by low-salinity spontaneous imbibition, and the values do not seem to correlate with either surface area or pore volume. The low response is believed to be caused by thermal effects from repeated heating and cooling of the samples during the preparations.
Our results cannot dismiss osmosis as an important mechanism for low-salinity EOR. Possible explanations for the correlation between increased oil production and pore volume are hysteresis and simultaneous connate water expansion throughout the core.
Wei, Bing (Southwest Petroleum University) | Zhang, Xiang (Southwest Petroleum University) | Lu, Laiming (Southwest Petroleum University) | Xu, Xingguang (The Commonwealth Scientific and Industrial Research Organization) | Yang, Yang (The Commonwealth Scientific and Industrial Research Organization) | Chen, Bin (CNOOC Enertech-Drilling & Production Co.)
Although the low salinity effect (LSE) in enhanced oil recovery (EOR) is widely accepted, its underlying mechanisms have not conclusively determined largely due to the complex interactions at oil/brine/rock interfaces and their relation with the dynamic flow behaviors in porous media. Given the vast diversity of brine composition in different reservoirs, the current studies are not yet sufficient to map the complicate interfacial behaviors. Therefore, the attention of this work was placed on the events that occurred on oil/brine/rock interfaces through direct measurements of oil water IFTs, interfacial dilational rheology, zeta potential and oil water relative permeability in sandstone porous media. The effect of brine composition including ion types, salinity and valency on LSWF was examined for the intent of re-defining the potential-determining-ions (PDIs) for LSE. The results showed that the oil water interfacial behaviors closely depended on the brine composition. The wettability alteration of the sandstone surface was found to be associated with the divalent ions and the double layer expansion (DLE) failed to interpreted the observed wettability in our work. The injection of MgSO4 brine produced the highest oil recovery factor compared to other three brine. On the basis of the previous observations, we concluded that the LSE was strongly dependent on the events occurred on the oil-brine-solid interfaces. The most significant LSE was observed at a salinity of 2000ppm in our work and the ions of Mg2+ and SO42− appeared to be critical for LSWF.
Numerical stability and precision are required when using simulations to predict Enhanced Oil Recovery processes and these can be difficult to achieve for Low Salinity Water Flooding (LSWF). In this paper we investigate the conditions that lead to numerical instabilities when simulating LSWF. We also examine how to achieve more precise simulation results by upscaling the flow behaviour in an effective manner.
An implicit finite difference numerical solver was used to simulate LSWF. The stability and precision of the numerical solution has been examined as a function of changing the grid size and time step. We used the Peclet number to characterise numerical dispersion with these changes. Time step length was compared with the Courant condition. We also investigated some of the nonlinear elements of the simulation model such as the differences between the concentrations of connate water salinity and the injected brine, effective salinity concentration range and the net mobility change on fluids through changing the salt concentration.
We observe that numerical solution of LSWF tends to be conditionally stable, with problems occurring as a function of the range of effective salinity concentration relative to the initial reservoir water and the injected brine concentrations. We observe that the Courant condition is necessary but not sufficient. By definition, the precision of the numerical solution decreased when increasing numerical dispersion but this also resulted in slowing down the low salinity water and increased the velocity of the formation water further reducing precision. These numerical problems mainly depend on fluid mobility as a function of salt concentration. We conclude that the total range and the mid-concentration of effective salinity affect the stability and precision of the numerical solution, respectively. In this work, we have developed two approaches that can be used to upscale simulations of LSWF and tackle the numerical instability problems. The first method is based on a mathematical form that gives the relationship between the fractional flow, effective salinity concentration and the Peclet number. The second method is that we have established an unconventional proxy method that can be used to imitiate pseudo relative permeabilities.
This work enables us for the first time to simulate LSWF by using a single table of pseudo relative permeability data, instead of two tables as traditionally done in previous studies. This removes the need for relative permeability interpolation during the simulation and will help engineers to more efficiently and accurately assess the potential for improving oil recovery using LSWF and optimise the value of the field development. We also avoid the numerical instabilities inherent in the traditional LSWF model.
Low-salinity waterflooding in limestone formations has been less explored and hence less understood in enhanced-oil-recovery (EOR) literature. The mechanisms leading to improved recovery have been mostly attributed to wettability alteration, with less attention given to fluid/fluid-interaction mechanisms. In this work, we present a thorough investigation of the formation of water-in-oil microdispersions generated when low-salinity brine encounters crude oil and the suppressed snap-off effect caused by the presence of sulfate content in seawater-equivalent-salinity brines as recovery mechanisms in limestone rocks. We believe this is a mechanism that leads to the improved oil recovery experienced with low-salinity waterflooding and seawaterflooding in carbonate formations. This novel interpretation was studied by integrating petrographic and spectroscopic observations, dynamic interfacial-tension (IFT) measurements, thermogravimetrical analyses, and coreflooding techniques.
Our data show that low-salinity brine caused a greater change in the crude-oil composition compared with seawater brine and formation-water brine. Formation-water brine created nearly no changes to the crude-oil composition, indicating its limited effect on the crude oil. These compositional changes in crude oil, caused by the low-salinity brine, were attributed to the formation of water-in-oil microdispersions within the crude-oil phase. Fourier-transform infrared (FTIR) spectroscopy data also showed that at brine-concentration levels greater than 8,200 ppm, this phenomenon was not experienced. Oil-production data for nonaged limestone cores showed an improved recovery of approximately 5 and 3% for seawater and low-salinity brines, respectively. Although the wettability-alteration effect was minimized by the use of nonaged cores, improved oil recovery was still evident. This was interpreted to represent the formation of water-in-oil microdispersions when low-salinity water (LSW) of 8,200-ppm salinity and less was used. The formation of the microdispersions is believed to increase the sweep efficiency of the waterflood by swelling and therefore blocking the pore throats, causing low-salinity-brine sweeping of the unswept pore spaces. Improved recovery by seawater brine was attributed to the changes in dynamic IFT measurement experienced using seawater brine as the continuous phase, compared with the use of LSW and formation-water-salinity (FWS) brine. This change caused a higher surface dilatational elasticity, which leads to a suppression of the snap-off effect in coreflooding experiments and hence causes improved oil recovery.
Our studies conclude that the formation of microdispersions leads to improved oil recovery in low-salinity waterflooding of limestone rocks. Furthermore, the use of seawater as a displacing fluid succeeds in improving recovery because of its high surface elasticity suppressing the snap-off effect in the pore throat. We also present an easy and reliable mixing procedure representative of porous media, which could be used for screening brine and crude-oil samples for field application. Fluid/fluid interaction as well as high surface elasticity should be investigated as the causes of wettability alteration and improved recovery experienced by the use of LSW and seawater-salinity (SWS) brines interacting with limestone formations, respectively.
An oil well blowout can burn like a rocket, which can be a good thing. Burning leaves little or no oil behind, according to a recent study (SPE 189610). The study has been used to make a case for an oil spill response plan now before regulators to develop a field with more than 100 million bbl of reserves in the Beaufort Sea. Plan approval is one of the remaining barriers facing Hilcorp, the operator in a partnership with BP to develop the Liberty field. If there is a blowout of a well on the gravel island that will be built for the project, the plan is to minimize the impact by igniting the well, and keeping it lit until a relief well can be drilled to plug it.