Statoil has submitted a plan for development and operation to Norwegian authorities for its Johan Castberg project--the northernmost development on the Norwegian Continental Shelf--after cutting its expected capital expenditure and break-even cost by at least half. Oil production is expected to start in the fourth quarter of 2022 and last 30 years. Located in the Barents Sea 240 km northwest of Hammerfest and 100 km north of Snohvit field, the Johan Castberg development will utilize a floating production, storage, and offloading (FPSO) facility and a subsea production system consisting of 30 wells with vertical subsea trees, wellheads, control systems, 10 templates and manifolds, two satellite structures, and tooling. The $6-billion project's estimated recoverable resources range from 450 million to 650 million BOE, mostly oil. Operating costs for the field are estimated at about $140 million/year.
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.
One of the biggest challenges in designing squeeze treatments is ensuring appropriate chemical placement along the completion interval. Generally, the chemical slug is bull-headed; therefore, in long horizontal wells and/or crossflow wells, exposing the chemical to all the completion intervals might be difficult. In this paper we introduce a method to evaluate placement efficiency. If placement is inadequate, some sections of the well will be unprotected, resulting in an undesirable situation: the well may appear to be protected because the inhibitor return concentrations measured at surface are above the threshold, but there is a loss of production due to scale deposition in areas of the well not contacted by chemical. In these circumstances inhibitor placement can be accurately determined by production logging, but this can be prohibitively expensive. An alternative is to use tracers to evaluate the layer flow rate distribution, and therefore quantify chemical placement. The objective of this paper is to determine if a tracer package could be deployed as part of a squeeze treatment in challenging wells, in particular in the overflush stage. If there are zones in the wellbore at different pressures, then producing the tracer back in steps at different rates will result in the tracer return concentration profile having characteristic features that can be interpreted to estimate chemical placement.
Two three layer cases with crossflow are considered. In both cases, a tracer package was included in the overflush, and the resulting return profiles showed clearly the desired features. The main advantage of this approach is that there is no significant increase in the operational expense. The only additional expense will be the cost of the specific tracer and the subsequent analysis. It is envisaged that the cost is less than 5% of the total squeeze treatment cost. The results of this novel multi-rate post squeeze production stage following injection of tracer demonstrate the feasibility of including such a tracer package in a squeeze treatment. Data collected may then be used to optimise the design of subsequent treatments, to ensure that appropriate placement is achieved by rate control or by diversion, if necessary.
Intelligent wells with inflow control valves enable flexible management of multiple reservoir intervals. In this paper, we describe model based optimization of inflow control valve settings for a producing North Sea field. A two step, non-invasive, iterative pattern search optimization algorithm is applied. The first step provides global search of the feasible region using a discrete genetic algorithm whereas the second step provides local search around the incumbent solution. To account for reservoir uncertainties, optimization is performed on a diverse set of history matched reservoir model realizations, within an automated framework. The results show a significant improvement in predicted reservoir production performance over the remaining life of the field.
Rock, Alexander (Clausthal University of Technology) | Hincapie, Rafael E. (Clausthal University of Technology) | Hoffmann, Eugen (Clausthal University of Technology) | Ganzer, Leonhard (Clausthal University of Technology)
This work provides an extensive review on Low Salinity Water Flooding (LSWF) recovery mechanisms, as well as an evaluation of its synergies with Polymer Flooding (PF). Thereby, a critical state-of-the-art evaluation on LSWF and PF mechanisms is combined with selective laboratory experiments, performed to illustrate the observations and findings. This evaluation can be used as a guidance to understand the expected behavior of both processes when applied in combination.
The work presented here comprises two main steps: 1) Comprehensive review of the mechanisms responsible of oil recovery in each process and 2) Predefined secondary and tertiary mode flooding experiments. First, oil recovery mechanisms associated to LSWF and PF have been analyzed in detail. Second, different field cases were compared in order to draw the main conclusions with regards to performance and recovery factors. This also helped to define the synergies of LSWF and PF in terms of technical and economic efficiency. Finally, secondary and tertiary mode experiments were performed to evaluate the feasibility of applying both processes.
Despite of the over 15 mechanisms reported in the literature for LSWF, six main mechanisms were identified that contributes to oil recovery. Mechanisms are described as: 1) Wettability alteration 2) Multi-ion exchange, 3) Fine migration, 4) Salting-in, 5) Double-Layer-Expansion and, 6) Other mechanisms, such as osmotic pressure and IFT reduction. Thereby, wettability alteration and fine migration have the highest significance. On the other hand, PF mechanisms were found to be: 1) Viscous fingering reduction, 2) Enhanced flow between layers, 3) Pull-out effects, 4) Shear thickening/elastic turbulence and, 5) Relative permeability reduction. LSWF field cases revealed incremental recoveries of up to 13% OOIP whereas synergies between LSWF and PF yielded to an additional recovery of 15% OOIP, underlining the potential of the combination of both EOR technologies. Selective LSWF-PF experiments performed in sandstones core-plugs in this work, allowed the verification of the additional recoveries reported in the literature. Tertiary flooding with solely LSWF, showed a lower recovery than tertiary LSWF-PF flooding. Moreover, this observation confirms the potentiality of polymer-combined LSWF in sandstones. Additionally, with the combined processes, a lower polymer concentration was required than applying a typically designed polymer flooding. This can be translated to an economic benefit for field applications.
Tertiary mode flooding experiments in sandstones and the analysis of field cases provided clear evidence of the advantages of LSWF-PF. This could yield that the processes -when applied in tandem- become a leading EOR strategy, ensuring the extension of the reservoir lifetime. Moreover, fellow researchers can benefit because the work provides a comprehensive review of Low Salinity Water Flooding and Polymer Flooding mechanisms. To the authors understanding, literature is currently lacking of such a review.
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.