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) | Buckman, Jim (Centre for Environmental Scanning Electron Microscopy, Heriot-Watt University)
The predictions of the performance of water-alternating-gas injection under near miscible and different wettability conditions using the current commercial reservoir simulators are very difficult and associated with significant uncertainties. Hence, experimental data are needed to tune reservoir simulators and optimize the performance of WAG injection in the field.
A series of coreflood experiments has been carried out, under ultra-low gas/oil interfacial IFT level, on the same sandstone core with three different wettability conditions; water-wet, weakly-water-wet and mixed-wet. In this study, we present the performance of WAG injection, in terms of oil recovery, under near miscible and weakly water-wet conditions in a homogenous sandstone rock and then comparisons of these results with those in water-wet and mixed-wet systems. To minimize the uncertainty that may associate with the experimental results, the same long and large sandstone core (2in × 2ft) was used in all of the coreflood experiments, presented in this paper, as well as the same core preparation and experimental procedure were repeated.
Analysis of the oil recovery profile, for weakly water-wet core, shows that about 62 % (IOIP%) of recovered oil was achieved by the preliminary water flood whereas an amount of 81.5 % (Sorw %) of the remaining oil, after water flood, was recovered by the alternation of water and gas injection cycles. The results of our coreflood experiments show also that the performance of secondary water flood increased as the direction of wettability changes from water-wet to mixed-wet, passing through weakly water-wet conditions. The oil recovery efficiency by different gas injection cycles, under near miscible and three different wettability conditions, increased as further WAG cycles carried out. However, their oil production rates decreased when wettability turns from water-wet towards mixed-wet system. Although the ultimate oil recoveries were 96.7 %, 92 % and 88.5 % (IOIP%) in mixed-wet, weakly-water-wet and water-wet respectively at the end of WAG injections, the overall oil recovery performance, post-waterflooding, was slightly higher in water-wet, then less in weakly water-wet and much lower in mixed-wet system. Comparison of the water and gas injectivity behaviors during near miscible WAG injection revealed that water and gas injectivity values increased when core wettability turns from water-wet towards mixed-wet, passing through weakly water-wet conditions.
Most of the existing three-phase relative permeability correlations were developed for water-wet system and however, they are widely applicable for a non water-wet reservoir. This has increased the uncertainties associated with those three relative permeability values especially for the data obtained for mixed-wet system. Hence, representative and accurate experimental data, for different wettability conditions, are needed to, firstly, obtain a reliable three-phase relative permeability and its hysteresis values, and secondly, to optimize the WAG process using the existing reservoir simulators.
The critical gas saturation in permeable sands was studied as a function of depletion rate and the presence of an aqueous phase as the major experimental variables. Voidage-replacement ratios (VRR = injected volume/produced volume) less than 1 were used to obtain pressure depletion with active water injection. Three different live crude oils were considered. Two of the oils are viscous Alaskan crudes with dead-oil viscosities of 87.7 and 600 cp, whereas the third is a light crude oil with a dead-oil viscosity of 9.1 cp. The critical gas saturation for all tests ranged from 4 to 16%. These values for critical gas saturation are consistent with the finding that the gas phase displayed characteristics similar to those of a foamy oil. For a given oil and depletion rate, the critical gas saturation was somewhat larger for VRR = 0 than it was for VRR = 0.7. The oil recovery correlates with the critical gas saturation (i.e., for a given VRR, tests exhibit greater oil recovery when the critical gas saturation is elevated). For the conditions tested, there was not a strong correlation of critical gas saturation over more than two orders of magnitude of the rate of pressure depletion, for a given VRR. Such behavior might be consistent with theoretical studies reported elsewhere that suggest that the critical gas saturation is independent of the pressure-depletion rate when the rate of depletion is small.
Group of microorganisms Example Metabolic Function Influence on corrosion Oxidizes Sulfide or other reduced sulfide pH may decrease locally.
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.
Water-alternating-gas (WAG) injection is a technique employed in EOR (Enhanced Oil recovery). WAG injection can be immiscible or immiscible with water and gas being injected into the hydrocarbon liquids reservoir to promote greater recovery. WAG injection is effective as gas typically has greater microscopic sweep efficiency whilst water has better macroscopic sweep efficiency. It is important to be able to characterise and quantify how much the degree and type of small/medium scale heterogeneity during WAG flooding could affect the recovery factor from a reservoir, such that during project evaluation teams are able to properly evaluate the ranges on uncertainty on recovery factors and the economic benefit of the project as well as risks associated with WAG implementation.
The Hutton field is located in the North Viking Graben area of the North Sea and the lithology of the reservoir section is made up of Brent group sandstones which are highly heterogeneous in the horizontal and vertical directions at a small scale (i.e. pore scale and plug scale) and at a medium scale (the vertical layering of different formations).
The effect of reservoir heterogeneity on WAG efficiency has been evaluated using dynamic reservoir simulation models of the Hutton field. Input parameters were based on an available model of the Hutton Field. A fine grid geological model (grid size 5ft × 5ft × ~2ft) has been created of a small section of the Hutton reservoir. A variety of field development schemes were evaluated including depletion, water injection, gas injection and immiscible WAG production scenarios. Geological models were created for three scales of heterogeneity (small scale and medium scale heterogeneity models, and a homogeneous model) based on interpretation of log data from a set of three control wells. Compositional simulation models were used to model the dynamic behaviour. Two phase relative permeability (oil / water and gas / oil) data was used, as three phase relative permeability data for Hutton was not available. There is no hysteresis data available for the Hutton field, therefore separate test runs were carried out to evaluate how hysteresis might affect recovery factor during WAG injection using two and three phase relative permeability data and parameters for use in the Killough correlation for hysteresis.
Immiscible WAG injection is beneficial in reservoirs with small and medium scale heterogeneity and gives ~5% improvement in recovery factor when compared to water injection. However, when hysteresis is included, the recovery factor may be higher than this by another ~10%. WAG injection may provide inferior recovery factors to water injection in homogeneous reservoirs. However, simulations indicated that some limited gas injection into a homogeneous reservoir may prove beneficial for accessing attic oil. It is recommended that laboratory testing of core samples (core flood experiments) be carried out prior to a WAG injection specifically with the aim of identifying the most appropriate hysteresis model and to give good relative permeability data across all three phases.
Proximity Sensing was recently proposed as way to simultaneously increase both range and resolution in cross-well EM tomography. The approach is applicable to reservoirs with resistive seals. Earlier reports were based on Finite Element Models (FEM) of layered structures, with dielectric and conductivity contrasts matching those of known reservoirs.
Experimental work, now reported, is consistent with expectations based on FEM simulations. Synthetic layered structures have been investigated using a 1.3 GHz Ground Penetrating Radar (GPR) system. Scaled reservoir model was constructed in a one-meter tank comprising sand with filled with fluids of variable dielectric constant and conductivity. In this system, dry sand, brine-saturated sand and a polymer foam provide a useful mimic for the electrical properties expected for a carbonate reservoir sealed by anhydrite. Water saturated porous media served as model bounding layers in analogy to known geologic structures. Data were recorded in the time domain using EM transients. Observed trends in velocities and amplitude shifts were consistent with FEM models. Interestingly, polarization dependent signal transport first indicated by FEM modeling was supported by these experimental results.
Results to date indicate that greatly increased EM propagation can be achieved through resistive geologic layers than directly through relatively conductive reservoir media. We confirm that these layers act as planar transmission lines and not as waveguides – meaning that there is no hard lower cutoff frequency and longer wavelengths can be used to sense and characterize reservoir fluids proximal to the dielectric channel. The results also confirm that variations in bounding layers modulate the amplitude and velocity of the signal in the dielectric channel and thereby demonstrate concept of Proximity Sensing.
These results support a new technical direction for EM characterization of reservoirs, especially in conjunction with magnetic contrast agents, enabling efficient localization of by-passed oil and mapping remaining oil columns in mature reservoirs.
Long-term petroleum reservoir management ideally optimizes production of oil while avoiding brine production and minimizing well count and complexity. Given imperfect knowledge of reservoir structure, significant inhomogeneity and dynamic multi-phase fluid saturation, this is a difficult and long-standing problem that would greatly reward improved methods for observing the state and structure of the reservoir in near real-time. This is particularly true in the case of mature fields in secondary production on waterflood. Modern reservoir models derived from 3D seismic, well logs and history matching are certainly a vital tool for reservoir management. However, our lack of knowledge about large-scale inhomogeneity, including facture corridors, prevent anticipation of early water breakthrough and bypass of significant volumes of oil. As such, there is a great need for imaging tools that can locate flood fronts, detect bodies of bypassed oil and map the remaining oil column thickness across the entire reservoir with sufficient resolution to guide key management decisions. Naturally, reservoir management would be easy if we had imaging modalities with petrophysical scale resolution (e.g. well logs ∼ 0.1 meter) over geophysical survey scales (e.g. seismic ∼ kilometers). However, imaging resolution requirements that can yield valuable and actionable information is probably much less challenging than that, and depends on direction and scale of the particular field under consideration. For the purposes of this paper, we will assert that for giant and super-giant fields (>> 1 B bbl), imaging modalities with resolution on the order of one meter vertically and up to several hundred meters laterally could respectively determine remaining oil column and flooded/bypassed volumes with sufficient accuracy to greatly improve reservoir management practice and development planning. Historic approaches for generating this kind of actionable information include direct full volume imaging using acoustic and low frequency electromagnetic (EM) probes. A new approach based on indirect EM imaging via Proximity Sensing will be described experimentally here.
In recent years, nanomaterials have attracted researcher's attention especially in the field of oil and gas. Nanomaterials based research results showed an improved performance in the areas of cement, drilling fluid and enhanced oil recovery. In this study, the effects of Boron Nitride (BN) microparticles on mechanical friction, fluid loss and viscosity were investigated. Boron Nitride (BN) microparticles were dispersed in a solution of Carboxymethylcellulose (CMC) and Fe2O3 nanoparticles were dispersed in Xanthan gum (XG) solution in water. Both fluids were treated with KCl and bentonite to create laboratory drilling fluid systems, which were studied at 22 °C.
The results show that the addition of 0.0095 wt. % BN and Fe2O3 reduced the mechanical friction coefficients of the laboratory drilling fluids by 37 %, and 43 %, respectively. Fe2O3 nanoparticles reduced the API static filtrate loss by 14.3 %, but the addition of BN didn't show any impact on filter loss. The particles have also shown an impact on the drilling fluid's viscosity parameters. The essence of this study is to understand the effect of nanoparticles on the drilling fluid performance and to get the better idea of how nanoparticles can contribute to improve the drilling fluid properties.
Scoppio, Lucrezia (Pipe Team srl) | Imbimbo, Emilia (RINA CONSULTING-Centro Sviluppo Materiali) | Axelsen, Sten (Statoil ASA) | Nice, Perry (Statoil ASA) | Mortali, Giuseppe (RINA CONSULTING-Centro Sviluppo Materiali)
Acid systems are used to improve productivity through either near-wellbore damage removal or through dissolving scale inside the wellbore during production. This paper describes the qualification methodology applied in the search for effective scale dissolvers/stimulation fluids with low corrosivity. The identification of suitable acid systems is becoming increasingly more challenging.
Furthermore, the operators try to lower the cost of the acid treatment itself. This may be achieved through optimization of the inhibitor package, which constitutes a significant part of the chemical cost.
A corrosion testing program was performed aimed at evaluating scale dissolver packages to determine which package(s) were least corrosive and acceptable for use in wells constructed with 3Cr80 alloyed steel and L80 13 Cr (API 5CT grade) (1) tubulars. Laboratory exposure corrosion tests were carried out at 60°C and 80°C. The scale dissolver packages consisted of 7.5%HCl, 15%HCl and 28%HCl including corrosion inhibitor packages. The main challenge was to optimize the acid formulation for 3Cr 80 alloyed steel. There is only limited data available for this material.
Corrosion resistance of the tested alloys was evaluated in terms of mass loss and localized corrosion. The results of this program successfully identified the optimized scale dissolver packages for both 3Cr80 alloyed steel and L80 13 Cr (API 5CT grade), respectively.
Acid systems are commonly used to improve productivity through either near-wellbore damage removal or through dissolving scale inside the wellbore during production. A number of different acid stimulation packages are available for removal of debris to permit unrestricted hydrocarbon flow. Acidic fluids can include different types of acids, such as hydrochloric (HCl), acetic, formic, or combinations of such acids. Since these can be corrosive, corrosion inhibitor packages are required to prevent severe corrosion damage to the well construction materials. Furthermore, inhibition additives for acid systems usage in North Sea oil wells require adherence to regulations calling for continual improvement in environmental characteristics while maintaining performance.1 As environmental standards are continually tightened, especially in the North Sea area, options for different corrosion inhibitor chemistries that will meet the criteria are becoming more limited. Challenging conditions for acid inhibition are ever present with (1) high temperatures, and (2) the use of metallurgies, e.g. 3Cr80 alloy steel, for which only limited data on scale treatments is available.2,3 3Cr80 has been developed as an economical material alternative for moderately corrosive services, and has been in service for more than 16 years as tubing on the Norwegian Continental Shelf (NCS).3
Immiscible Water Alternating Gas (IWAG) is an EOR process whereby water and immiscible gas are alternately injected into a reservoir to provide better sweep efficiency and reduce gas channelling from injectors to producer wells, aiming to stabilize the displacement front and increase contact with the unswept areas of the reservoir. In this work, we present a summary of best practices for laboratory evaluation of IWAG. This work was motivated by observations related to the way laboratory measurements are normally done, which could result in erroneous interpretation if the results were to be used directly for the design of a field application.
The set of best practices were collected from own work expanding over two decades of laboratory work, discussion with experts from laboratory services and research centres, and a comprehensive literature review. They were tested in a laboratory workflow and compared to conventional workflows used by most laboratories. The recommended approach covers steps from sample preparation, experimental setup, measurement protocols, guideline for process design, and data QA/QC for later use in reservoir simulation.
Among the best practices, particular attention is given to the type of fluids and samples used for the measurements based on the strong effect of rock-fluid interactions on the IWAG performance. The layout of the experimental setup, and how the injection and displacement process is done and the flow effects quantified. Other best practices relate to the selection of the WAG slug ratio, and required initial conditions of the core where the laboratory testing is done. The number of cycles in the WAG injection affects the recovery. On the initial condition of the sample, the knowledge of the sample wettability at the start of the WAG is critical since the optimum ratio is influenced by the wetting state of the rock. A WAG ratio of 1:1, which is the most popular in field applications, is not necessarily the most appropriate.
Regarding flow properties, relative permeability should be evaluated under three-phase conditions and making sure hysteresis effects are well captured data in general not readily available. Special attention should be given to the selection of correlations for calculating three-phase relative permeability widely reported in the literature; in most cases they are not accurate for WAG injection since they do not consider special treatment of water-gas cycle.
We present a side by side comparison of the impact on the laboratory results will be given on using recommended best practices to more routine laboratory implementations. These best practices, with focus on immiscible WAG, provide a new unique workflow for the execution of laboratory programs supporting a better understanding of the involved phenomena and providing accurate data for immiscible WAG process design.
Schedule Session Details Expand All Collapse All Filter By Date All Dates Wednesday, November 01 Thursday, November 02 Friday, November 03 Filter By Session Type All Sessions Social and Networking Events Technical Sessions Panel, Plenary, and Special Sessions Wednesday, November 01 09:30 - 10:30 Conference Opening Ceremony To mark the opening of the SPE Annual Caspian Technical Conference and Exhibition in Azerbaijan, industry luminaries will address delegates and journalists, providing insight and vision on the oil and gas industry in the Caspian region. Darcy Spady 2018 SPE President Academician Khoshbakht Yusifzade First Vice President SOCAR Brant Hasebe Vice President Reservoir Development BP Azerbaijan, Georgia and Turkey Region Denis Lemarchal Managing Director TOTAL E&P Azerbaijan Ibrahim Guliyev Vice President National Academy of Sciences Oleg Karpushin Executive Vice President Operations, Production and Oil Field Services JSC NC KazMunayGaz Ted Etchison General Director Tengizchevroil Mars Khasanov Technology Director Gazprom Neft PJSC Sergey Kolbikov Head of Reservoir Engineering NOVATEK Ali Al-Jarwan Chief Executive Officer and Managing Director Exploration and Production Dragon Oil 10:30 - 11:00 Coffee Break and Knowledge Sharing Poster Session 11:00 - 12:30 Opening Keynote Panel Session: Modernisation Moderator(s) Darcy Spady, 2018 SPE President Speaker(s) Abzatdin Adamov, ADA University; Mars Khasanov, Gazprom Neft; Sergey Kolbikov, NOVATEK; Yves Le Stunff, TOTAL E&P; Oddvar Vermedal, Statoil Session Manager(s): Brant Hasebe, BP; Ilkam Mukhametshin, RESMAN Abzatdin Adamov Director Center for Data Science Research and Training ADA University Mars Khasanov Technology Director, Gazprom Neft PJSC Sergey Kolbikov Head of Reservoir Engineering NOVATEK Yves le Stunff TOTAL E&P Oddvar Vermedal Vice President, IT Statoil The energy industry, characterised as both capitally intensive and requiring robust risk management, has historically been relatively slow to accept new technology and ways of working. Key contractors are inclined to deploy existing tools to minimize capital expenditure on equipment upgrades. High entry costs, particularly against the backdrop of geographic and market constraints, can result in limited competition. High commodity prices can make good performance ‘good enough.’