Interwell tracers have been shown to provide invaluable information about reservoir dynamics, well connectivity, and fluid flow allocations. However, tracer tests are often applied sporadically because their immediate returns of investments are not readily apparent to a resource-holder. Here, we rigorously demonstrate that tracer data can indeed improve reservoir history matching, and, more importantly, improve future production, using reservoir simulations on benchmark problems. Sensitivity studies and the limitations of tracer data are also provided.
The numerical experiments were divided in two sections. First, production data with or without tracer data from reference fields were collected for the first water flooding periods for history matching. Second, the history matched models from the first section were used for production optimization for the next water flooding periods. The ensemble smoother with multiple data assimilation (ES-MDA) was used for the history matching processes for the first part of the numerical experiments, and the modified robust ensemble-based optimization (EnOpt) was adopted to maximize the net present value (NPV) for the second part of the numerical experiments.
The three-dimensional channelized "Egg Model" was chosen as the initial benchmark problem. From the first part of the numerical experiments, using the same hyper-parameters, it was observed that history matching including tracer data resulted in a better match of the field production rates with smaller standard deviations. In addition, history matching including tracer data resulted in more distinct geological features when observing the history matched permeability maps. From the second part of the numerical experiments, we observed that the geological models history matched including tracer data resulted in better production optimization with higher NPV produced. In the specific case of the Egg Model, +4.3% increase of the NPV was observed.
To understand the sensitivity and the limitations of the tracer data, the same numerical experiments were performed on a library of reservoir models with different fracture patterns. After the history matching and production optimization simulations, we observed that including tracer data gave positive NPV increases ranging from +0.3% to +9.4% from 5 of the 7 test cases. It was observed that tracers were more effective for the non-homogeneously flooded reservoirs.
To the best of our knowledge, this paper is the first study that quantifies the benefits of tracers in the context of the improved production, measured in NPV. In a broader perspective, we believe this is the best way to test any new history matching algorithms or reservoir surveillance methods. In this work, we show that tracers can result in positive NPV in most situations, and oil producers using large-scale water flooding operations would benefit from performing more tracer tests in their operations.
Modeling foam flow through porous media in the presence of oil is essential for various foam-assisted enhanced oil recovery (EOR) processes. We performed an in-depth literature review of foam-oil interactions and related foam modeling techniques, and demonstrated the feasibility of an improved bubble populationbalance model in this paper. We reviewed both theoretical and experimental aspects of foam-oil interactions and identified the key parameters that control the stability of foam lamellae with oil in porous media. Upon reviewing existing modeling methods for foam flow in the presence of oil, we proposed a unified population-balance model that can simulate foam flow both with and without oil in standard finite-difference reservoir simulators. Steadystate foam apparent viscosity as a function of foam quality was used to evaluate the model performance and sensitivity at various oil saturations and fluid velocities. Our literature review suggests that, among various potential foam-oil interaction mechanisms, the pseudo-emulsion-film (gas/aqueous/oil asymmetric film) stability has a major impact on the foam-film stability when oil is present.
Carbonate rocks are typically heterogeneous at many scales, leading to low waterflood recoveries. Polymers and gels cannot be injected into nonfractured low-permeability carbonates (k < 10 md) because pore throats are smaller than the polymers. Foams have the potential to improve both oil-displacement efficiency and sweep efficiency in such carbonate rocks. However, foams have to overcome two adverse conditions in carbonates: oil-wettability and low permeability. This study evaluates several cationic-foam formulations that combine wettability alteration and foaming in low-permeability oil-wet carbonate cores. Contact-angle experiments were performed on initially oil-wet media to evaluate the wettability-altering capabilities of the surfactant formulations. Static foam-stability tests were conducted to evaluate their foaming performance in bulk; foam-flow experiments (without crude oil) were performed in porous media to estimate the foam strength. Finally, oil-displacement experiments were performed with a crude oil after a secondary gasflood. Two different injection strategies were studied in this work: surfactant slug followed by gas injection and coinjection of surfactant with gas at a constant foam quality. Systematic study of oil-displacement experiments in porous media showed the importance of wettability alteration in increasing tertiary oil recovery for oil-wet media. Several blends of cationic, nonionic, and zwitterionic surfactants were used in the experiments. In-house-developed Gemini cationic surfactant GC 580 was able to alter the wettability from oil-wet to water-wet and also formed strong bulk foam. Static foam tests showed an increase in bulk foam stability with the addition of zwitterionic surfactants to GC 580. Oil-displacement experiments in oil-wet carbonate cores revealed that tertiary oil recovery with injection of a wettability-altering surfactant and foam can recover a significant amount of oil [approximately 25 to 52% original oil in place (OOIP)] over the secondary gasflood. The foam rheology in the presence of oil suggested propagation of only weak foam in oil-wet low-permeability carbonate cores.
Water chemistry has been shown to affect oil recovery by affecting surface charge and rock dissolution. The single-well chemical-tracer (SWCT) test is a field method to measure residual oil saturation (Sor), in which hydrolysis reaction of an ester has been known as a key process that could displace the equilibrium state of a reservoir by changing formation-water (FW) composition.
Because oil mobilization during the SWCT tests causes an error in the measurement of Sor, changes in water chemistry might be a concern for the accuracy of Sor measurements. In our previous work, the extent to which different reservoir parameters might change water composition and the effect of water-chemistry changes on the calcite dissolution and the oil liberation from the carbonate-rock surfaces were extensively evaluated. In this study, the effect of water-chemistry changes on surface-charge alteration at the carbonate/brine interface has been studied by constructing and applying a surface-complexation model (SCM) that couples bulk aqueous and surface chemistry. We present how the pH drop induced by the displacement of the equilibrium state and changes in water chemistry in the formation affect surface charge in a pure-calcite carbonate rock during the SWCT tests.
The results show that a pH drop during the SWCT tests while calcium concentration is held constant in the FW by ignoring calcite dissolution yields a less-positive/more-negative surface charge so that wettability of carbonate rock might be altered to a less-oilwetting state, when the oil is negatively charged. In reality, however, calcite dissolves by water-chemistry changes during the SWCT tests, which leads to an increasing calcium concentration in the FW. Consequently, an SWCT test in carbonates is accompanied by increasing calcium concentration while pH drops, which yields an increase in the surface charge of carbonate rocks. Therefore, the pH drop does not directly affect the surface charge of carbonate rock during an SWCT test, and calcium concentration increased from calcite dissolution could control the surface charge more significantly.
This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system.
This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.
AlAbbad, Mohammed A. (Saudi Aramco) | Sanni, Modiu L. (Saudi Aramco) | Kokal, Sunil (Saudi Aramco) | Krivokapic, Alexander (Institutt for Energiteknikk) | Dye, Christian (Institutt for Energiteknikk) | Dugstad, Øyvind (Restrack) | Hartvig, Sven K. (Restrack) | Huseby, Olaf K. (Restrack)
The single-well chemical-tracer test (SWCTT) is an in-situ test to measure oil saturation, and has been used extensively to assess the potential for enhanced oil recovery (EOR) or to qualify particular EOR chemicals and methods. An SWCTT requires that a primary tracer be injected and that a secondary tracer be generated from the primary tracer in situ. Typically, a few hundred liters of ester is injected as primary tracer, and the secondary tracer is formed through hydrolysis in the formations. The ester is an oil/water-partitioning tracer, whereas the in-situ-generated alcohol is a water tracer. During production, these tracers separate and the time lag of the ester vs. the alcohol is used to estimate oil saturation in the near-well region.
In this paper, we report a field test of a class of new reacting tracers for SWCTTs. In the test, approximately 100 cm3 of each of the new tracers was injected and used to assess oil saturation. In the test, ethyl acetate (EtAc) was used as a benchmark to verify the new tracers. This paper reviews the design and implementation of the test, highlights operational issues, provides a summary of the analyzed tracer curves, and gives a summary of the interpretation methodology used to find oil saturations from the tracer curves. Briefly summarized, we find the Sor measured by each of the novel tracers to compare with that from a conventional SWCTT. To validate stability and detectability of the tracers, a mass-balance assessment for the new tracers is compared with that of the conventional tracers.
A benefit of the new tracers is the small amount needed. Methodological advantages resulting from using small amounts include the possibility to inject a mix of several tracers. Using several tracers with different partitioning coefficients enables probing of different depths of the reservoir. In addition, the robustness of SWCTTs can be increased by using several tracers, with different reaction rates and temperature sensitivity. The field trial also demonstrated that the new tracers have operational advantages. One benefit is the possibility to inject the new tracers as a short pulse of 10 minutes. Other benefits are that the small amounts needed reduce operational hazards and ease logistical handling.
The first intelligent completion was deployed in the Snorre field offshore Norway in August 1997, marking a major milestone for advanced completion engineering, reservoir insight, and production control. For the first time, an operator could manipulate tubing outflow performance at, or near, the sandface inflow node, without intervention or workover, but rather live via remote control using an interval control valve (ICV). Twenty years later, technological advancements have significantly increased the reliability and capability of intelligent completion tools with applications in ultra-deepwater, mature fields, as well as in the cost-sensitive unconventional arena.
This paper discusses the significant technological advancements and reliability of ICVs by comparing the following: case history examples of technology, applications, and installations from the past and present; associated technological and operation challenges with solutions and resulting reliability increases; and a view of the future design and reliability aspects of ICVs with respect to hydraulic vs. electric control and actuation. ICV case history examples are discussed below:
Comparing two field-wide offshore deepwater Africa campaigns in 2007 and 2015 with respect to ICV reliability, operational improvements, and technology from eight years of continuous improvement. Using a remotely operated hydraulic ICV installed above the production packer as a circulating device and a gas-tight barrier. This ICV was actuated through pressure signals to a battery-operated control module and micro-hydraulic pump vs. control lines to surface. History of ICVs installed as part of the mature fields of the Middle East and why high-actuation force will always be a requirement. A current high rate water injection completion campaign as part of an offshore mature field in which ICV position sensors transmitting choke positions in real time have significantly increased the operator's confidence of zonal-flow allocation. A Middle East operator's current application for low-cost ICVs. History of ICVs installed in multi-lateral completions and why they should stay in the motherbore.
Comparing two field-wide offshore deepwater Africa campaigns in 2007 and 2015 with respect to ICV reliability, operational improvements, and technology from eight years of continuous improvement.
Using a remotely operated hydraulic ICV installed above the production packer as a circulating device and a gas-tight barrier. This ICV was actuated through pressure signals to a battery-operated control module and micro-hydraulic pump vs. control lines to surface.
History of ICVs installed as part of the mature fields of the Middle East and why high-actuation force will always be a requirement.
A current high rate water injection completion campaign as part of an offshore mature field in which ICV position sensors transmitting choke positions in real time have significantly increased the operator's confidence of zonal-flow allocation.
A Middle East operator's current application for low-cost ICVs.
History of ICVs installed in multi-lateral completions and why they should stay in the motherbore.
The steady increase in ICV reliability is the result of advancing technology, as well as continuous improvement in operational procedures. These case histories help detail each advancement.
The future of intelligent completions and ICVs is tied to precision of device control, system reliability assurance, and effective use of sensor data to generate recognizable value. Precision and data require electronic control and transmission; however, hydraulic actuation offers more advantages with current available technology. This paper concludes with an argument for the future of practical ICV installation, zone control, actuation, and closed-loop operator interface.
Alkhazmi, Bashir (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Farzaneh, S. 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) | Sisson, Adam (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University)
In this study, the effect of rock type on two-phase and three-phase flow and displacements have been experimentally investigated as a part of a study on the performance of WAG injection in sandstone and carbonate rocks. A series of core flood experiments have been performed under reservoir conditions to investigate the effect of parameters pertinent to the performance of WAG injection. Clashach sandstone and Indiana limestone cores with almost similar porosity and permeability were selected for this work. To reduce the effects of experimental artifacts, large cores were used with diameter and length of 2 in × 2 ft respectively. To investigate the role of rock type, the WAG design parameters including injection order, injection strategy, and slug size were kept unchanged for the sandstone and carbonate rocks. Both core flood experiments were performed on water-wet cores and at near-miscible gas/oil IFT conditions.
Comparison of our core flood experiments reveal that even though the waterflood efficiency was higher in carbonate core than in sandstone rock, the overall oil recovery performance by the alternation of water and gas injections in the sandstone rock outperformed its trend in the carbonate core. Ultimate oil recovery values of 88.35 % (IOIP %) and 71.0 % (IOIP %) were obtained for the sandstone and the carbonate cores, respectively. The results show that about 39.12 % (IOIP %) and 12.37 % (IOIP %) of additional oil was recovered by the alternation of water and gas injection in the sandstone and carbonate cores, respectively. Comparing the average saturation profiles in the cores revealed that the higher trapped gas saturation in sandstone rock had significantly enhanced its oil recovery performance, during the tertiary water and gas injections, compared with that in the carbonate rock. The results also revealed the impact of rock type on pressure drop and fluid saturation distribution.
Double layer Expansion (DLE) is proposed as one of the mechanisms responsible for Improved Oil Recovery (IOR) during Low Salinity Water Flooding (LSWF). This expansion is triggered by the overlap between the diffuse double layers. We performed molecular simulation to study this phenomenon where both kaolinite and montmorillonite are used as substrates contacting water with varying concentration of monovalent and divalent ions. Our results, and several molecular simulations, have confirmed that the location of the adsorption planes is independent of the ionic strength. However, the potential developed on these surfaces and how it decays depends on both the ionic strength and ion nature. A shrinkage is observed in the double layer for the case of low salinity, supported by both film thickness estimations and interaction energy analysis. This shrinkage, which contradicts the prevailing assumption, is consistent with molecular simulation studies, and casts some doubts on the efficiency of DLE as a mechanism for explaining IOR observed during LSWF. This brings into question the role of double layer expansion in enhancing oil recovery, and raises the need to investigate other mechanisms that could be responsible for the experimental and field observations made in this area.
Water alternating gas (WAG) injection is a common technique in enhanced oil recovery. However, gas injection often associates with fingering due to high gas mobility, which leaves a large portion of the reservoir unswept. This study addresses gas mobility control observations through novel X-ray microfocus visualization of core-flood experiments and interpretation aided by numerical simulation. We use foam as our primary mobility control agent for improving conformance.
The experimental setup utilizes an automated fluid injection system monitored by an X-ray microfocus scanner to quantify displacement patterns and saturations during WAG core-flood experiments. The core-flood device – placed within an X-ray shielded cabinet – is wirelessly operated through a computer. The resolution of the images permits observation of not only core scale fingering but also pore-scale displacement. We use a metastable foam with surfactant dissolved in the liquid phase to stabilize the gas diffusion in the liquid and to decrease the permeability and/or lower the apparent gas viscosity.
Results show that saturation patterns and displacement front during WAG injection are highly influenced by bedding orientation and rock heterogeneity. Without gas mobility control during WAG injection, fingering and early breakthrough occur in those cases in which bedding orientation facilitates gas to flow through high permeability layers. In these cases, sweep efficiency is low during early time injection of nitrogen and only improves after injection is prolonged. With gas mobility control, the displacement efficiency is significantly improved. Also, dynamic processes like phase trapping, which could severely impair permeability and overall sweep efficiency, is more clearly visualized with the microfocus technique. Simulation work matches experimental data well and replicates saturation patterns measured experimentally in laminated Berea sandstone samples.
The novel visualization technique presented here provides new pore-scale experimental insight to quantifying WAG displacement in heterogeneous media, a resolution one order of magnitude higher than with medical X-ray CT or other core-scale visualization techniques. The findings are useful for understanding flow regimes in structurally complex and heterogeneous formations.