A systematic approach to characterize the mixed wet configurations of various reservoir rocks (sandstone and carbonates) by evaluating their surface energy distributions has been presented in this paper. This approach was tested against the macroscopic spatial distribution of oil-wet and water-wet sites and at different temperatures for validation.
The new approach used to characterize the mixed wettability of a reservoir rock pertains to establishing a relation between the volume fraction of the mixed-wet reservoir rocks and surface energy of the mixture. This approach is based on an accurate description of the various physico-chemical interfacial forces present at the reservoir rock surface using Inverse Gas Chromatography (IGC). Mixed-wet configurations of various reservoir rocks are created by combining water-wet and oil-wet samples of the rock in different volume fractions and shaken together to establish uniform distribution. These samples are then subjected to the IGC analysis at different temperatures to deduce their surface energy distribution. The relation developed herein is tested against spatial heterogeneity by combining the oil-wet and water-wet rock samples in a layered fashion to validate the approach. The complete method to deduce the surface energy distribution of a rock surface using IGC has also been explained in detail.
A definite and conclusive relationship between the surface energy and mixed wettability of silica glass beads, calcite, and dolomite samples was established in this study. The mixed-wet configurations of the rock samples ranged from 0% oil-wet (meaning water-wet samples) to 100% oil-wet samples. The findings indicated that the Lifshitz-van der Waals component of the rock mixture did not undergo any change with change in the wetting state of the system under study. However the acid base components showed a marked decrease with increasing oil wetness before plateauing. Temperature was found to have a profound impact on the surface energy of a rock surface. Spatial heterogeneity by way of layered and segregated distribution of oil-wet and water-wet sites did not affect the eventual surface energy distribution thereby validating the new approach.
Fluorinated benzoic acids (FBA) have been widely used in the oil industry as conservative tracers. However, some of these tracers have been shown to rapidly degrade when tested at temperatures above 121°C within three weeks. Naphthalene sulfonates (NSAs) have been shown to be excellent tracers in geothermal applications. However, a broader study was required to determine tracer conservation in reservoir fluids and formations typically encountered in the oil field.
In this study we compare the oil field industry standard FBA tracers to NSA tracers under dynamic test conditions in the presence of reservoir oil, sandstone, carbonates and clays. We also compare the two sets of tracers under static conditions in the presence of four crude oils and different clay mineralogy to establish tracer conservation. Seven different sodium salts of naphthalene sulfonic acids were tested to determine if the tracers were adsorbed onto natural porous media (reservoir rock) at reservoir conditions. A broad range of conditions were selected to target typical reservoirs encountered. In addition, reservoir rock and a pseudo formation containing 10 Wt.% clay in silica sand were used in sand packs saturated with surrogate brine to ensure the tracer recovery under dynamic conditions.
High pressure liquid chromatography (HPLC-FLD) separation was used for simultaneous detection of seven NSAs while FBAs were analyzed using HPLC-UV. GC analysis of isopropyl alcohol (IPA) was used as a standard against which the others were measured.
Dynamic tracer tests demonstrated that the sodium salts of naphthalene sulfonates behaved similarly to the control, IPA, with none of the tracers adsorbing on to the rock surface or partitioning into the oil phase. The naphthalene sulfonates can be successfully used as conservative tracers most specifically for high temperature applications. NSA tracers are an attractive replacement for conservative FBA tracers in the oil field due to their superior thermal stability, solubility in oil field brine, lower detection limits and cost.
Favorable microemulsion rheology is required for achieving low surfactant retention and economic viability of chemical EOR. Co-solvents play a pivotal role in obtaining favorable microemulsion rheology as well as many other aspects of chemical EOR. We measured the partitioning of co-solvents between phases to better understand their behavior and how to select the best co-solvent for chemical EOR. There is an optimal co-solvent partition coefficient for microemulsion systems. Commercial co-solvents used for chemical EOR are actually mixtures of different components. We used HPLC to measure the partitioning of the constitutive components of phenol ethoxylate co-solvents between oil and water phases and between microemulsion and excess oil and water phases. These measurements show that the components partition independently and the partitioning of individual components is often different from the average. The co-solvent partition coefficients between oil and water were systematically evaluated as functions of the number of ethylene oxide groups, number of propylene oxide groups, temperature, salinity, and the equivalent alkane carbon number (EACN) of the oil. Novel alkoxylate co-solvents were also evaluated for chemical EOR. The novel alkoxylate co-solvents can be more effectively tailored to match the characteristics of different crude oils. Coreflood experiments were conducted to investigate co-solvent transport and retention. Co-solvents were identified that showed excellent performance and low retention.
Given limited CO2 supply, operational constraints, and pattern specific reservoir performance, WAG schedule can be customized such that NPV or other metrics are optimized. Depending on the WAG schedule, recovery can fluctuate between 5–15% at the pattern scale due to reservoir heterogeneity causing variations in sweep efficiency. An analytical method was developed to optimize WAG schedules that couples traditional reservoir modeling and simulation with machine learning, enabling the discovery of optimal WAG schedules that increase recovery at the pattern level. A history-matched reservoir model of Chaparral Energy's Farnsworth Field, Ochiltree County, TX was sampled intelligently to perform predictive reservoir flow simulations and artificially build an intelligent reservoir model that samples a broad range of possible WAG scenarios for optimization. The intelligent model generates the next "best" sample to investigate in the numerical simulator and converges on the optima, quickly reducing the number of runs investigated. Results in this paper demonstrate that there can be significant improvements in net present value as well as net utilization rates of CO2 using this analytical technique. The WAG design generated by the intelligent reservoir model should be deployed in the field in early 2016 for validation. It is intended that the intelligent reservoir model will be updated on a regular basis as injection and production data is obtained. This effort represents the beginning of a paradigm shift in the application of modeling and simulation tools for significant improvements in field production operations.
The prediction of polymer degradation under reservoir conditions is critical to EOR polymer selection. NMR studies were used to monitor the changes in the anionic content of acrylamide containing polymers. The monomer sequence distribution of hydrolyzed polyacrylamide polymers (HPAM) was monitored during lab test to improve our understanding of HPAM stability. The results suggest that accelerated aging of a polymer at reservoir conditions at elevated temperatures will result in a polymer with structure similar to the polymer resulting from extended aging at lower temperatures.
In most reservoirs around the world, paleo oil exists below the free water level and is considered residual oil to natural/geological waterflood. This non-trivial resource of residual oil will not flow by primary or secondary recovery means but requires carefully designed enhance oil recovery (EOR) methods to mobilize it. To date, there is no detailed analysis of paleo oil in the literature simply because it is difficult to obtain a reservoir sample.
This study provides a comprehensive paleo oil analysis for samples obtained from reservoir sponge cores. The oil in the sponge core was extracted, analyzed, and compared to main pay zone oil (MPZ). Critical data have been unveiled on paleo oil characterization through fundamental studies on oil quality, fingerprint, filling history, available hydrocarbon components and compounds, and molecular level characterization. It was found that the global composition and overall quality of paleo oil is very similar to the MPZ oil. However, the differences between the two oils were only apparent when the study was further extended to include molecular level analysis and available hydrocarbon components and compounds. These differences may define the appropriate the EOR methods to mobilize this oil and explain trapping mechanisms caused by fluid properties.
Gas chromatography studies revealed that paleo oil extracts have the same Pristane/Phytane ratio as the MPZ oil suggesting that they are of the same origins and share the same source rock. Further analysis showed a good match of the Terpane biomarkers between paleo oil extracts and MPZ oil but with slightly less maturity levels. Paleo oil quality was compared to MPZ oil using Pyrolytic Oil Productivity Index (POPI) analysis which indicated same API range as the MPZ oil and same light volatile, thermally distilled and cracked components. Paleo and MPZ oils were also analyzed using nuclear magnetic resonance (NMR) to qualitatively test the similarity of the oil components and measure their apparent viscosities. Both oils have shown very comparable viscosity measurements and NMR signatures. The simulated distillation analysis showed that lighter components in paleo oil are less abundant than MPZ oil while medium to heavy components are relatively similar. Fourier Transform Ion Cyclotron Resonance (FT-ICR) study, which zoomed into the heavier components, revealed that paleo oil has less aromaticity than MPZ oil and lacks aromatic sulfur and di-sulfur compounds, negligible amount of nitrogen compounds, and no resin type components.
This study provides in depth information about oil extracted from the residual oil zone, which doesn't flow by primary or secondary recovery means. Up to our knowledge, there is no available information in the literature that explains the components, compounds, quality and behavior of this oil because it is hard to obtain reservoir samples. This data shed light on possible trapping mechanism caused by fluids in place. The study also employed several methods and tools to confirm the conclusions and ensure repeatability of results.
MEOR (microbial enhanced oil recovery) is known as one of the emerging low-cost EOR technologies, which uses in-situ microorganisms living in the oil field. Some of the most promising microbial-induced mechanisms include production of extracellular polymeric sugars (EPS), biofilms as well as selective plugging caused by cell growth. However, there is limited data available concerning the way microbes and biofilms behave in contact to surfaces in porous media in the context of MEOR. The aim of this work was to investigate bacterial growth and biofilm production in the framework of an ongoing MEOR project conducted by Wintershall and BASF. We used various approaches to investigate cell behavior of a halophilic bacterial community derived from a Wintershall oil field. Bacterial growth was conducted in both batch cultures and under dynamic conditions. To visualize cell adhesion and also exopolymers occuring in biofilms we used specific fluorescent dyes. During incubation of the microbes over several weeks we could visualize different types of EPS under the microscope. This observation fits perfectly to a concurrent viscosity increase of the surrounding media. Modelling approaches were applied to estimate the potential contribution of these effects on additional oil recovery. The observations including cell clumping, sorption and polymer production were geometrically quantified and the effect of the modifications on permeability profile and resulting flow characteristics was numerically investigated with fluid dynamic simulations of the petrophysical changes. The potential implications of the observed changes on EOR capability by conformance control and wettability modification were further estimated with analytical approaches. With the developed methods for visualization and modelling of the microbes and biofilms in both batch and dynamic conditions, we are able to monitor the clumping and sorption behavior of the cells, which will help to interprete data obtained during an upcoming MEOR field trial.
Ghasemi, M. (Petrostreamz AS) | Astutik, W. (Petrostreamz AS) | Alavian, S. A. (PERA AS) | Whitson, C. H. (PERA AS/NTNU) | Sigalas, L. (Geological Survey of Denmark and Greenland) | Olsen, D. (Geological Survey of Denmark and Greenland) | Suicmez, V. S. (Maersk Oil & Gas A/S)
This paper presents a novel technique to determine multi-component diffusion coefficients for CO2 injection in a North Sea Chalk Field (NSCF) at reservoir conditions. Constant volume diffusion (CVD) method is used, consisting of an oil-saturated chalk core in contact with an overlying free-space, which is filled with the CO2. The experimental data are matched with an EOS-based compositional model.
Transport by diffusion controls the dynamics of the constant-volume system, together with phase equilibria, allowing a consistent estimation of diffusion coefficients needed to describe the observed changes in system pressure.
We conduct two experiments at reservoir condition: one utilizes a core plug saturated with live-oil, and the other with stock tank oil (STO). Once the experiments are completed, EOS-based compositional simulation is performed to match the experimental data using the oil and gas diffusion coefficients as history matching parameters. The modeling work is conducted with a commercial reservoir simulator using a two dimensional radial grid model to describe the experimental setup.
The experiment utilizes a vertically-oriented core holder with a height of 92 mm and 37.6 mm in diameter. An outcrop chalk core with a sealing sleeve is mounted in the core holder, which has the same diameter and a height of 64.6 mm, thus resulting in an overlying void space. The system is initially saturated with oil at reservoir condition. CO2 is then injected from the top, forming an overlying CO2 chamber, and displacing oil towards the bottom of the core holder. Once CO2 fills the overlying bulk space, the system is isolated with no further injection or production.
The CO2 and oil reach and remain in equilibrium locally at the gas-oil interface throughout the test, initiating and maintaining the diffusion mechanism. Diffusion of CO2 into the oil results in a decreasing pressure, which is the main history matching parameter.
The multi-component diffusion coefficients are found to match the model pressure-time prediction to the experimental data. This suggests the modelling workflow incorporates a representative EOS model and the main transport dynamics controlled by diffusion are being treated properly.
The two main challenges in the modeling are (1) the limitation on setting an appropriately-high permeability for the CO2 chamber, and (2) the reservoir simulator neglects compositional dependency of diffusion coefficients.
Proper simulation of CO2 injection in fractured chalk reservoirs requires the ability to model multi-component diffusion accurately. The proposed CVD-method provides such modeling capabilities. Our modeling and experimental work indicate the novelty of the CVD method to determine the diffusion coefficients of a system where diffusion is the dominant displacement mechanism. The fact that the oil is contained within a low-permeability chalk sample reduces density-driven convection that could result due to non-monotonic oil density changes as CO2 dissolves into the oil.
The application of surfactants to improve oil recovery in conventional reservoirs via wettability alteration and enhancement of spontaneous imbibition has been extensively studied in the literature. However, little work has been performed yet to investigate the interaction of these surfactants with ultra-tight oil-rich shale reservoirs such as Wolfcamp shale. The use of horizontal drilling and massive multistage hydraulic fracturing has made primary oil recovery from these ultra-tight oil-rich shale reservoirs possible. With declining production from existing shale wells, it is essential to explore potential "beyond primary" strategies in shale oil development. This paper analyzes the potential of surfactants in altering wettability and improving the process of spontaneous imbibition in oil rich shales demonstrating nanodarcy range permeability, relevant to stimulation and "beyond primary" chemical EOR applications in shales.
Novel proprietary surfactant blends along with traditional nonionic surfactants were investigated in this study using Wolfcamp shale core samples exhibiting nanodarcy permeability. X-ray diffraction analysis was performed which indicated that Wolfcamp shale has mixed mineralogy, with quartz, calcite, and dolomite acting as the major minerals in varying proportions depending on the interval depth. Contact angle and interfacial tension measurements were performed at reservoir temperature to identify the state of native wettability and the impact of surfactants in altering wettability. Thereafter, spontaneous imbibition experiments were performed using 3D computed tomography methods to understand the improvement in the magnitude of imbibition penetration due to surfactant addition. Contact angle and spontaneous imbibition experiments showed that Wolfcamp shale is intermediate-wet and surfactants have the potential to alter the native wettability to a preferentially water-wet state and improve oil recovery due to enhanced spontaneous imbibition.
Surfactants which altered the wettability significantly, but lowered the interfacial tension only slightly showed the highest oil recoveries due to the creation of strong capillary driven forces directly responsible for effective spontaneous imbibition. The potential of surfactants in altering wettability and improving oil recovery via enhanced spontaneous imbibition in ultra-tight oil-rich shales was verified in this study. The effectiveness of traditional nonionic surfactants in altering wettability and improving oil recovery was found to be comparable to that of novel, more expensive proprietary surfactant blends, and hence, the traditional nonionic surfactants provide a cost effective option for stimulation and EOR applications in Wolfcamp shale. Overall, this paper presents the theory behind surfactant interaction with ultra-tight shales and provides experimental results to validate the viability of surfactant induced improved oil recovery in shales.
Enhanced-oil-recovery techniques by gas injection in shale reservoirs have been introduced and investigated. Laboratory and simulation works have shown good results for enhanced shale oil recovery, but one problem with gas injection is asphaltene precipitation and deposition. Damage due to asphaltene precipitation and deposition in conventional reservoirs has been reported in the literature. In shale reservoirs, pore and throat sizes are much smaller than in conventional reservoirs. Thus, large asphaltene aggregates may cause more serious problems in shale reservoirs.
This experimental study used a nanofiltration technique to investigate the size of asphaltene aggregates precipitated during CO2 and CH4 injection in a shale oil sample. Nano membranes of 200nm, 100nm and 30nm were used to filtrate oil samples injected with different mole fractions of CO2 and CH4 gas. The distribution of asphaltene aggregates’ size at different injected CO2 and CH4 concentrations were obtained and compared with the pore size distribution data of shale cores measured by mercury intrusion porosimeters. Results showed that a higher injected CO2 and CH4 concentration caused more asphaltene precipitation and growth in asphaltene aggregates’ size. The precipitated asphaltene particle size was large enough to cause a pore-blocking problem in tested shale cores.