bluuebunny/crossref_metadata_2025 huggingface dataset:
New Type Curve Analysis Removes Limitations of Conventional After-Closure Analysis of DFIT Data
Authors: Craig David P.
Published: June 2014

Prefrac pressure diagnostics, including fracture-injection/falloff sequences, have been used for several years to estimate initial reservoir pressure and transmissibility in unconventional reservoirs. Prior to performing pressure diagnostics, initial or average reservoir pressure is almost always unknown, and many times the purpose of a pressure diagnostic is to determine initial reservoir pressure. As shown by several authors, when a pressure diagnostic falloff exhibits bilinear, linear, or radial flow, the initial or average reservoir pressure can be determined from special plots using straight-line analysis methods. However, correctly identifying the flow regimes during a pressure falloff is often very difficult, and the tendency is to incorrectly apply straight-line analysis methods to data on a specialized plot that often does not correspond to a bilinear, linear, or radial flow regime. In many cases, bilinear, linear, or radial flow will not be observed in any of the falloff data, and valid estimates of initial reservoir pressure and transmissibility cannot be determined using straight-line methods.

This paper presents a new type curve analysis method that removes the limitations of conventional after-closure straight- line analysis of pressure diagnostics. Like conventional well test analysis, the new method fits observed pressure data to analytical type curves, and type curve match points are used to determine initial reservoir pressure, transmissibility, fracture half-length, fracture conductivity, and fracture damage. Type curve analysis has proved especially useful for post-frac evaluation of stimulation effectiveness, and has also proved useful in shale reservoirs where it is often difficult to determine if a dilated fracture or fracture network close completely, with no conductivity or retained residual width. Understanding dilation/contraction properties of a shale fracture network can provide important guidance for fracture treatment design and optimization. Type curve analysis has also reduced the amount of shut-in time required to obtain a quantitative estimate of reservoir and fracture properties albeit with increasing uncertainty as shut-in time decreases.
Statistical Reverse Model to Predict Mineral Composition and TOC Content of Marcellus Shale
Authors: Wang G. , Carr T. R. , Ju Y.
Published: June 2014

Unconventional shale reservoirs possess low matrix permeability and cannot produce economically without effective placement of horizontal laterals and effective hydraulic stimulation.It is critical to recognize brittle units amenable to hydraulic fracturing and rich in organic matter. Shale mineralogy affects not only the effectiveness of stimulation, but also the ratio of free to absorbed gas. Heterogeneity in shale reservoirs expressed by mineral composition, organic matter richness and brittleness significantly influences shale-gas production. Although providing the necessary information, core data and pulsed neutron spectroscopy (PNS) logs are limited by cost considerations to an insufficient number of wells in order to sufficiently characterize reservoir heterogeneity.

We present an approach of petrophysical analysis and statistical reverse modeling to better determine mineral concentration, organic matter percentage, and volume of gas and water using conventional logs in the Marcellus Shale (Appalachian basin, USA). Core data and PNS logs are utilized to guide and demonstrate the results. The statistically based reverse model incorporates random errors of logging, and solves mineral composition through matching the or iginal logs with mineralogy models. The effectiveness of statistical reverse models is enhanced through removing the effects of minerals with significant petrophysical response (e.g., barite) and fluids. Barite strongly affects the mineralogical estimates in shale. The concentration of such minerals can be predicted by the difference between PE curve and a trend line. Fluid volumes are predicted by a modified shaly-sand model with uranium concentration through understanding the effect of organic matter.

The methodology proposed provides an approach to predict mineral composition and organic richness and the corresponding mineralogical properties (e.g., geomechanical and free-to-absorbed gas ratio). The proposed approach aids in recognizing geologic and engineering targets, designing horizontal well trajectories, targeting fracturing strategies and understanding shale depositional environments and processes. The proposed approach can be extended to other organic -rich shale reservoirs.
3D Structural Modeling and Property Characterization for Optimized Completion Design in the Wolfcamp Formation, Delaware Basin
Authors: Azike O. , Ajisafe F. , Pope T. , Burkhardt C. , Helmreich A. , Phelps M.
Published: June 2014

For a well in the Permian Basin, openhole (OH) triple combo logs from five nearby offset wells and gamma ray from a horizontal well were used to deduce a workflow to define the 3D structural geometry of the drilled horizontal section. After establishing the structural architecture of the drilled lateral section to determine which part of the lateral is in or out of zone, lithology and petrophysical properties from the offset wells were propagated using geostatistical algorithms to match the horizontal well path. A relatively distant offset well with an advanced log suite was also utilized to generate synthetic mechanical rock properties along the lateral. These data were used for optimized completion design by placing stimulation stages in similar rock and intelligently placing perforation clusters. Placement was guided by rock type and geomechanical properties as opposed to geometrical spacing along the lateral.

The assumption that rock properties are homogenous and structural dip is fairly constant in horizontal drilling has been proven to be untrue in recent studies, and production logs have shown that not all stages/perforation clusters contribute to production. The consequence of not using image log measurements in geosteering the lateral to ensure that the lateral is in the target reservoir can lead to ineffective stimulation treatment and possibly skipping stages in parts of the lateral that is landed in a higher stress rock.

The successful application of the workflow enabled us to determine the structural geometry along the drilled horizontal well and also build a 3D structural and property model, which was successfully used for the optimized stimulation staging and completion design. This produced a more successful stimulation treatment with approximately 67% more sand placed per stage compared to an offset well drilled in the same target zone.
Wellbore Monitoring in Unconventional Reservoirs: Value of Accurate DTS Interpretation and Risks Involved
Authors: Kalia Nitika , Gorgi Sam , Holley Eric , Cullick A. S. , Jones Tim
Published: June 2014

Wellbore monitoring techniques are proving to be significant in reservoir management and intervention design, particularly in unconventional fields where fluid flow behavior is not very well understood. Distributed temperature sensing (DTS) technology allows for an estimation of zonal flow rates in the entire well as a function of time during hydraulic fracturing, as well as during the production phase.

In this work, a novel transient thermo-hydraulic model that includes fluid transport and thermal coupling and simulates fluid flow and temperature in both the wellbore and reservoir is presented. Real DTS data from a hydraulic fracturing operation in a low-permeability basin in west Texas has been inverted using this model. Flow allocation based on the thermo-hydraulic model is presented. It was found that the reservoir heterogeneity, and hence the zonal flow rates, can be accurately obtained based on temperature and pressure data from the well.

Most of the steady-state DTS data inversion models are typically applicable to production scenarios, where the transient in temperature has vanished. Injection operations, such as in fracturing where the temperature does not achieve a steady- state during the injection stage, require a transient model that can capture the initial-time effects. Also, some of these models fail to include the Joule-Thomson effect, and this leads to an incorrect flow allocation. The thermo-hydraulic model developed in this work includes both the Joule-Thomson and transient effects. It can be applied to non-reactive fluid injection during stimulation operations, such as matrix acidizing and fracturing. In particular, application of the model for fluid distribution before, during, and post-fracturing provides an estimate of the efficiency of fracturing stages.
The Effect of Osmotic Pressure on Improve Oil Recovery from Fractured Shale Formations
Authors: Fakcharoenphol Perapon , Kurtoglu Basak , Kazemi Hossein , Charoenwongsa Sarinya , Wu Yu-Shu
Published: June 2014

Shale swelling during drilling is attributed to osmotic pressure, where low-salinity water enters the shale pores to cause swelling. Low-salinity water injected into high-salinity Bakken formation could similarly enter the matrix pores to displace oil by counter-current flow observed in core experiments. As a result, we believe, low-salinity water can potentially enhance oil recovery from oil-wet Bakken formation.

In this paper, we report experimental and numerical modeling studies we conducted to evaluate the potential of low- salinity waterflooding in Bakken. For laboratory experiments, we used horizontal core plugs drilled parallel to the bedding plane.

The mathematical included osmotic pressure, gravity and capillary effects. In the mathematical model, the osmotic pressure mass transfer equations were calibrated by matching time-dependent salinities in a published laboratory osmotic pressure experiment. We also modeled oil recovery for a Bakken core using our osmotic pressure mass transport model. The results indicate that osmotic pressure promotes counter-current flow of oil from both the water-wet and oil-wet segments of the core.
Experimental Investigation of Enhanced Recovery in Unconventional Liquid Reservoirs using CO2: A Look Ahead to the Future of Unconventional EOR
Authors: Tovar Francisco D. , Eide Øyvind , Graue Arne , Schechter David S.
Published: June 2014

The poor rock quality and matrix permeability several orders of magnitude lower than conventional oil reservoirs observed in unconventional liquid reservoirs (ULR) presents many uncertainties on the storage capacity of the rock and the possibility of enhancing recovery. The technological advances in multiple stage hydraulic fracturing and horizontal drilling have improved the overall profitability of oil shale plays by enhancing the matrix – wellbore connectivity. The combination of these technologies has become the key factor for the operators to reach economically attractive production rates in the exploitation of ULR, causing a lot of focus on their improvement. However, as the reservoir matures, primary production mechanisms no longer drive oil to the hydraulic fractures, making the improvement of matrix – wellbore connectivity insufficient to provide economically attractive production rates. Therefore, the need to develop enhanced recovery techniques in order to improve the displacement of the oil from the matrix, maintain profitable production rates, extend the life of the assets and increase ultimate oil recovery becomes evident.

This study presents experimental results on the use of CO2 as an enhanced oil recovery (EOR) agent in preserved, rotary sidewall reservoir core samples with negligible permeability. To simulate the presence of hydraulic fractures, the ULR cores were surrounded by high permeability glass beads and packed in a core holder. The high permeability media was then saturated with CO2 at constant pressure and temperature during the experiment. Production was monitored and the experiment was imaged using x-ray computed tomography to track saturation changes inside the core samples.

The results of this investigation support CO2 as a promising EOR agent for ULR. Oil recovery was estimated to be between 18 to 55% of OOIP. We provide a detailed description of the experimental set up and procedures. The analysis of the x-ray computed tomography images revealed saturation changes within the ULR core as a result of CO2 injection. A discussion about the mechanisms is presented, including diffusion and reduction in capillary forces. This paper opens a door to the investigation of CO2 enhanced oil recovery in ULR.
Zonal Isolation Technology Enables Production without Post-Frac Intervention
Authors: Allen R. , Oberg L.
Published: June 2014

Hydraulic fracturing in unconventional reservoirs has increased rapidly in the past ten years. Each year, technologies are improved and methodologies are refined, making this process faster, safer, and more economical.

Currently, plug-and-perforate is the most common type of hydraulic fracturing diversion method. During this type of operation, composite plugs are spaced into a wellbore to divert the hydraulic fracturing treatment to a specific zone in the reservoir. After each wellbore has been thoroughly fractured, coiled tubing or threaded pipe, in tandem with positive displacement motors, is summoned to remove the composite plugs from the wellbore to enable production.

This paper will describe a new zonal isolation technology that will provide operators with a number of benefits that improve operational efficiency and enable earlier production. The benefits from this technology include eliminating the necessity for composite plug removal after the conclusion of all zonal stimulations, and a far larger than traditional ID through which high-rate flowback and production can be accommodated. An integral aspect of this technology is the use of disintegrating fracturing balls that rapidly deteriorate after stimulation. By eliminating composite plug removal, operators will spend fewer days on location, reducing HS+E risks. Operators can also complete longer lateral wellbores more quickly and economically. In general, operators will also realize reduced total zonal completion cost and achieve quicker production when compared to traditional plug-and-perf completion methods. Finally, this new zonal isolation technology may enable future intervention for re-stimulation operations, if required.

As exploitation of unconventional reservoirs grows globally, this technology will give operators more flexibility in designing completions, particularly in remote locations.
Effect of Dissolved Iron and Oxygen on Stability of HPAM Polymers
Authors: Seright R. S. , Skjevrak Ingun
Published: June 2014

This paper describes an experimental study of the stability of an HPAM polymer and an HPAM-ATBS terpolymer in the presence of varying initial levels of dissolved oxygen (0 to 8000 parts per billion, ppb), Fe2+ (0 to 220 parts per million, ppm), and Fe3+ (0 to 172 ppm). A special method was developed to attain and confirm dissolved oxygen levels. Stability studies were performed at 23°C and 90°C. For Fe2+ concentrations between 0 and 30 ppm, viscosity losses were insignificant after one week so long as the initial dissolved oxygen concentration was 200 ppb or less. Above this level, significant viscosity losses were seen, especially if iron was present.

If the temperature is high, a greater need arises to strive for very low dissolved oxygen content. For samples stored for one week at 90°C with only 10-ppb initial dissolved oxygen, contact with steel caused HPAM-AMPS solution viscosity losses greater than 30%. In contrast at 23°C, contact with steel caused no significant degradation so long as the dissolved O2 concentration was 1000 ppb or less. Several different methods are discussed to control oxidative degradation of polymers during field applications. We advocate physical means of excluding oxygen (e.g., stopping leaks, better design of fluid transfer, gas-blanketing, gas-stripping) over chemical means.

Addition of Fe3+ to polymer solutions caused immediate crosslinking. Since crosslinked polymers were never observed during our studies with Fe2+, we conclude that free Fe3+ was not generated in sufficient quantities to form a visible gel.
Modeling Development of a Thermal Gas-Oil Gravity Drainage Process in an Extra-Heavy Oil Fractured Reservoir
Authors: Niz-Velásquez E. , Bagheri S. R. , van Dorp J. J. , Jennings J.
Published: June 2014

Thermal Gas-Oil Gravity Drainage (T-GOGD) is an attractive Enhanced Oil Recovery (EOR) method applicable to naturally-fractured reservoirs (NFR). The process is successfully applied in Qarn Alam, a heavy oil field in Oman. This paper presents a dynamic modeling optimization and uncertainty analysis workflow for T-GOGD in a bitumen-bearing fractured reservoir based on realistic 3D fracture characterization.

In T-GOGD, the fractures are displaced to steam to provide a (matrix) gravity drainage potential while heating the reservoir at the same time. One of the recovery mechanisms associated with T-GOGD is thermal expansion, which can result in high initial rates, but may cause plugging of the fracture system in the case of extra-heavy oil (bitumen) if the expanded oil cools down before it is being produced. This situation requires short-distance well configurations and/or steam stimulation cycles to establish communication. In a NFR, steam vapour occupies the fracture system while oil drains through the matrix, increasing the area for heat transfer with respect to the steam chamber case; the process therefore differs significantly from SAGD and a different production function applies.

Shell's in-house reservoir simulator MoReS with advanced dual-permeability capability, is used to model development of T-GOGD in a bitumen reservoir employing 3D element-of-symmetry models. A realistic fracture characterization and modeling process is described. The geometrical well configuration and operating schedule and strategy are optimized on an economic function for a deterministic subsurface realization. Using an uncertainty analysis workflow, cumulative distribution functions of recovery and steam-oil ratio are generated. Finally, robust optimization is explored using an economic objective function. The study concludes that 1) relatively large well spacing is feasible while injector-producer horizontal well offset is necessary to avoid steam channeling to the producer well, 2) live steam production control is a robust operating strategy, 3) performance is most sensitive to matrix permeability and oil viscosity, and 4) vertical fracture connectivity plays an important role on the process performance. T-GOGD has significant potential to develop bitumen resource in naturally fractured carbonates.
Field Testing the Polysaccharide Schizophyllan: Results of the First Year
Authors: Leonhardt Bernd , Ernst Burkhard , Reimann Sabrina , Steigerwald Alexander , Lehr Florian
Published: June 2014

For the first time ever a novel biopolymer is being field tested in a mature onshore oil field in Northern Germany. This biopolymer – named Schizophyllan after its producing fungus – shows excellent viscosifying efficiency and high tolerance towards harsh reservoir conditions such as high temperature, salinity and shear. Hence, this biopolymer allows for application in reservoirs that could so far not be polymer flooded and extends the operating envelope for polymer flooding to temperatures up to 275°F at arbitrary salt contents. Furthermore, it provides an environmentally friendly alternative to the commonly used synthetic polymers.

To run this first field test petroleum engineers of Wintershall Holding GmbH, chemical research scientists and biotechnologists of BASF SE are closely cooperating in an integrated team. An existing biotechnological plant at the BASF compound in Ludwigshafen, Germany, was partly reconstructed into a production facility for providing sufficient biopolymer for the field pilot. In the oil field itself an existing production site was extended into an operation site also hosting the surface facilities for treatment of the produced water used for re-injection and preparation of the injected biopolymer solution.

Being trucked to site as mother solution the Schizophyllan is mixed on-the fly with the treated, high-salinity reservoir brine and injected into a newly drilled injector in the project area surrounded by three production wells. A comprehensive surveillance program was set up comprising regular microbiological sampling, pressure monitoring using permanent down-hole gauges as well as frequent analyses and production tests to monitor the progress of the polymer trial.

The paper presents further information on the biopolymer Schizophyllan, describes the preparation and the setup of the field trial and summarizes results and experiences from the first year of the two-year field trial.
Imbibition Characteristics of Marcellus Shale Formation
Authors: Morsy Samiha , Gomma A. , Sheng J. J.
Published: June 2014

In order to understand the effect of injected stimulation fluids on nano-darcy permeability, naturally fractured shale reservoirs, an integrated study of spontaneous imbibition was performed. In this study, oil recovery during spontaneous imbibition in naturally fractured shale samples was investigated using different water formulations. Different water solutions were formulated by adding different amounts of HCl and NaOH to either distilled water or 2 wt% KCl-base brine solution. Eight water formulations, distilled water, 2% KCl brine, low pH HCl solutions (0.74-1.2), and high pH alkaline solutions (11.78-12.4) were examined to recover oil from shale rocks. Outcrop samples from Marcellus shale formation were used in this study. The samples were 2.54 to 3.81 cm in diameter and 0.762 to 5.08 cm in length. Firstly, we studied the average porosity of the used samples using CT Scanning. The average porosity was around 6%. Secondly, we studied the rock stability and spontaneous imbibtion of the different Marcellus samples in distilled water, 2 wt% KCl, low pH solutions (0.741.2), and high pH alkaline solutions (11.78-12.43). During the spontaneous imbibition, the maximum oil recovery was 4% using low pH solution of pH0.74 (3 wt% HCl in 2 wt% KCl base brine solution) or high pH solutions (pH11.9 and pH12.4). There was no difference between the oil recoveries achieved by distilled or 2 wt% KCl solution which might indicate that Marcellus shale is not sensitive to salinity. Oil recoveries from Marcellus shale slightly improved when using low or high pH solutions due to wettability alteration that has been supported by the changes in the measured contact angles before and after exposure to such solutions. The rock hardness of Marcellus samples was significantly affected by using both high and low pH solutions, which resulted in 55-94% loss of its initial value using low pH solutions and 50-68% when using high pH solutions.
Adsorption of a Switchable Cationic Surfactant on Natural Carbonate Minerals
Authors: Cui Leyu , Ma Kun , Abdala Ahmed A. , Lu Lucas J. , Tanakov Ivan , Biswal Sibani L. , Hirasaki George J.
Published: June 2014

A switchable cationic surfactant, e.g., tertiary amine surfactant Ethomeen C12, has been previously described as a surfactant that can be injected in high pressure CO2 for foam mobility control. C12 can dissolve in high pressure CO2 as a nonionic surfactant and equilibrate with brine as a cationic surfactant. Here we describe the adsorption characteristics of this surfactant in carbonate formation materials. The adsorption of this surfactant is sensitive to the equilibrium pH, the electrolyte composition of the brine, and the minerals in carbonate formation materials.

Pure C12 is a nonionic surfactant. When it is mixed with brine, the solution has high pH and limited solubility. However, when the surfactant solution in brine is equilibrated with high pressure CO2, the pH is about 4, the surfactant switches to a cationic surfactant and becomes soluble. Thus the adsorption is also a function of pH. The adsorption of C12 on calcite at low pH is low, e.g., 0.5 mg/m2. However, if the carbonate formation contains silica or clays, the adsorption is high, as is typical for cationic surfactants. The adsorption of C12 on silica decreases with increase in divalent (Ca2+ and Mg2+) and trivalent (Al3+) cations. This is due to the competition for the negatively charged silica sites between the multivalent cations and the monovalent cationic surfactant. An additional effect of the presence of divalent cations in the brine is that it reduces the dissolution of calcite or dolomite in presence of high-pressure CO2. The dissolution of calcite and dolomite is harmful because of formation damage and increased alkalinity. The latter raises the pH and thus increases adsorption of C12 or even cause surfactant precipitation.
Simulation of Polymer Injection under Fracturing Conditions - A Field Pilot in the Matzen Field, Austria
Authors: Zechner Markus , Clemens Torsten , Suri Ajay , Sharma Mukul M.
Published: June 2014

Polymer flooding leads to enhanced oil recovery by accelerating oil production and improving sweep efficiency. However, owing to the higher viscosity, injectivity of polymer solutions is of some concern and is important to understand to predict incremental oil recoveries. Achieving high polymer injection rates is required to increase oil production rates.

In the field test performed in the Matzen field (Austria), polyacrylamide polymers have been injected for the past two years. Core flood experiments with these polymers showed a significant increase in apparent viscosity due to the viscoelastic properties of the polymer solutions. Also, severe degradation of the polymer solution at high flow velocities was detected. In addition to core flood experiments, flow experiments through fractures were performed. In these experiments, shear-thinning and limited degradation of the polymer solution was observed and quantified.

Detailed polymer injection simulations were conducted that included complex polymer rheology in the fractures and the matrix. The reservoir stress changes and its effects on the fractures were also taken into account due to cold polymer injection. The results of the simulations matched the field data both for water floods and polymer test floods.

The simulations revealed two distinct phases during injection of the polyacrylamide polymer solutioninjection under matrix conditions in an early phase resulting in severe degradation of the polymers andinjection under fracturing conditions once the formation parting pressure is reached, leading to limited degradation of the polymers.

The calibrated model was used to investigate the impact of polymer rheology and particle plugging on injectivity and fracture growth.

The results of the field test and the simulations indicate that screening of fields for polyacrylamide polymer projects need to include geomechanical properties of the reservoir sand and cap/base rock in addition to the conventional parameters used in the simulations such as oil viscosity, water salinity, reservoir temperature and reservoir permeability. Furthermore, it is shown that water quality is crucial for polymer EOR operations.
Efficient Experimental Data Acquisition for Miscible CO2 WAG Injection Corefloods in Carbonate
Authors: Duchenne Sebastien , Puyou Gilles , Cordelier Philippe , Hy-Billiot Joelle , Hamon Gerald
Published: June 2014

Understanding the physics behind which CO2 and water displaces oil in the porous medium is of the utmost importance for the success of any miscible CO2 water-alternating-gas (WAG) injection project. Coreflood experiments have to be designed efficiently to provide relevant information about complex three-phase flow mechanisms and ensure precise measurements of key reservoir parameters such as trapped gas saturation, CO2 relative permeability curves and hysteresis effects.

This paper presents an experimental study to investigate the effect of miscible cyclic CO2 injection on three phase relative permeability by performing a series of coreflood experiments in horizontal carbonate cores with light oil from a Middle East field. These experiments are designed using innovative data acquisition techniques to ensure data quality and allow accurate determination of reservoir microscopic properties. Produced volumes are monitored to provide material balance of each phase at both reservoir and laboratory conditions with a clear separation of flashed oil, condensate and gas. A full compositional analysis is then conducted, using gas chromatography and liquid analysis of flashed oil and condensate, providing essential information for recovery calculation. Differential pressure across the core is also monitored for relative permeability estimation. Finally, in situ saturation profiles are acquired in real time during experiments, using a dual energy X-Ray scanner for three-phase calculations. Redundancy in measurements, along with rigorous accounting of measurement uncertainties, allows a successful cross-check of all acquired data.

Methods of saturation estimation are discussed. Results show that for miscible corefloods, recovery strongly depends on how swelling and stripping mechanisms are accounted for.
Study of Particle Structure and Hydrophobicity Effects on the Flow Behavior of Nanoparticle-Stabilized CO2 Foam in Porous Media
Authors: Yu Jianjia , Wang Sai , Liu Ning , Lee Robert
Published: June 2014

Studies of supercritical CO2 foam stabilized with amorphous and crystalline silica nanoparticles at reservoir conditions were carried out for the CO2 foam enhanced oil recovery (EOR) application. In this paper, three types of silica nanoparticles, consisting of crystalline and amorphous structures, as well as different wettabilities, were employed to study the effects of particle structure and wettability on supercritical CO2 foam generation. The effects of silica nanoparticle structure and hydrophobicity on supercritical CO2 foam behaviors such as foam morphology, foam resistance factor and mobility were investigated under the conditions of a wide range of phase ratios and total flow rates. Our results showed that CO2 foams stabilized by crystalline silica and amorphous silica exhibit similar flow behaviors. The hydrophobicity of nanosilica plays the most important role for CO2 foam generation; the CO2 bubble size decreased significantly with the increase in hydrophobicity of silica nanoparticles. The silica nanoparticle with the highest hydrophobicity shows the greatest reduction of foam mobility under the conditions of wide-ranged phase ratios and total flow rates.
Integration of Reservoir Simulation and Time-Lapse Seismic in Delhi Field: A Continuous CO2 Injection EOR Project
Authors: Chen T. , Kazemi H. , Davis T. L.
Published: June 2014

In assessing the effectiveness of any CO2 enhanced oil recovery projects, it is essential to track the flow path of injected CO2 and determine the bypassed oil pockets. The objective of this research was to construct a high definition, dynamic reservoir model that can support reservoir management activity. Time lapse seismic is an effective tool for monitoring CO2 movement and deciphering flow channels in the reservoir. Reservoir engineers use mathematical simulation, which is constrained by production-injection data, to determine displacement efficiency and dynamic changes in pressure and saturation in the reservoir. Reservoir simulation also serves as a prediction tool to evaluate the economics of the CO2 projects. Both time-lapse seismic analysis and reservoir simulation can complement each other to increase the resolution of CO2 flow path and CO2 – effectiveness.

The paper presents integration of geology, geophysics and engineering for assessing a continuous CO2 injection EOR project in Delhi Field, Louisiana. The CO2-targeted formations are Tuscaloosa and Paluxy sandstones. The production and injection activities in Delhi Field result in changes in fluid saturations and pore pressure. These changes affect properties of the reservoir rock and fluids, which can be detected by time-lapse seismic analysis as P-wave anomalies. A geologic model was built using well logs, petrophysical measurements and seismic inversion for the Reservoir Characterization Project (RCP) area. We built two reservoir simulation models, including black oil and an eleven-component compositional model, based on the reservoir geologic model as the first step in the integrated research effort. We obtained production history matches for the primary, secondary and tertiary phases of the field operation.

The simulated flow paths of the injected CO2 agree well with the time-lapse seismic interpretations. This agreement validates the effectiveness of integrating geologic modeling, reservoir simulation, and time-lapse seismic analysis in assisting field operations and maximizing oil recovery efficiency.
Survelliance of Secondary and Tertiary Floods: Application of Koval's Theory to Isothermal Enhanced Oil Recovery Displacements
Authors: Jain Lokendra , Lake Larry W
Published: June 2014

Fluids injected during secondary and tertiary floods often leave parts of the reservoir unswept mostly because of large heterogeneity and mobility ratio. Several applications require an analytical scheme that could predict production with as few parameters possible. We develop such an analytical model of volumetric sweep that aims to apply an extension of Koval's theory (Jain and Lake, 2013) where flow is assumed to be segregated under vertical equilibrium conditions for secondary and tertiary displacements. The original Koval factor is applicable for upscaling secondary miscible floods. The new analytical model for secondary and tertiary floods is applied to provide quick estimates of oil recovery of miscible as well as immiscible displacements, which is then calibrated against field data. The model parameters: Koval factor, sweep efficiency and pore volume, estimated after history matching could be used to make reservoir management decisions. The model is very simple; history matching can be done in a spreadsheet. Single-front, gravity-free, displacements can be modeled using Koval factors. Two-front, gravity-free, displacements can also be modeled using Koval-type factors for both the fronts. These Koval-type factors, coupled with laboratory scale relative permeabilities, allows for scaling the displacement to a larger reservoir system. The new method incorporates by-passed pore volume as a parameter, a difference between this work and that of Molleai (2012), along with Koval factors and local front velocities. For two front displacements, it also accounts for the interaction between the fronts which honors correct mass conservation, another difference with the work of Molleai (2012). The results from new models for secondary and tertiary displacements were verified by comparing them against numerical simulations. The application is also demonstrated on actual field examples. Current techniques for reservoir surveillance rely on numerical models. The parameters on which these numerical models depend on are very large in number, introducing large uncertainty. This technique provides a way to predict performance without the use of computationally expensive fine scale simulation models, which could be used for reservoir management while reducing the uncertainty.
Ammonia as Alkali for ASP Floods – Comparison to Sodium Carbonate
Authors: Southwick Jeffrey G. , van den Pol Esther , van Rijn Carl H. , van Batenburg Diederik W. , Boersma Diederik M. , Svec Yi , Mastan Ahmad Anis , Shahin Gordon T. , Raney Kirk
Published: June 2014

Ammonia is logistically preferred over sodium carbonate for alkaline-surfactant-polymer enhanced oil recovery projects (ASP) due to its low molar mass and the possibility for it to be delivered as a liquid. On an offshore platform space and weight savings can be the determining factor in deciding whether an ASP project is feasible. Logistics may also be critical in determining the economic feasibility of projects in remote locations.

Ammonia functions as an effective alkali together with a surfactant blend of alkyl propoxy sulfate – internal olefin sulfonate (APS/IOS). Surfactant adsorption is low and oil recovery in core floods is high. Static adsorption tests show that low surfactant adsorption is attained at pH > 9, a condition that ammonia satisfies at low solution concentration.

It is expected that ammonia has a performance deficiency relative to sodium carbonate in that it does not precipitate calcium from solution. Calcium accumulation in the ammonia ASP solution will occur due to ion exchange from clays. The high oil recovery for ammonia and the calcium accumulation in ASP and SP core floods with APS-IOS blends shows that this surfactant system is effective and calcium-tolerant. Also, phase behavior and IFT measurements suggest that APS/IOS blends remain effective in the presence of calcium. EO/PO sulfates (such as the employed APS) are well known commercially available, calcium-tolerant surfactants. However, due to hydrolysis sulfate-type surfactants such as APS are suitable for use only in lower temperature reservoirs.

Very different behavior was noticed for phase behavior measurements with calcium intolerant surfactants such as alkyl benzene sulfonates (ABS) and internal olefin sulfonates (IOS). In this case calcium addition results in a very high IFT and complete separation of oil and brine. Presumably this will result in low oil recovery. A preferred approach for ASP offshore with divalent ion intolerant surfactants may be the use of a hybrid alkali system combining the attributes of sodium carbonate and ammonia. The concept is to supply the bulk of the alkalinity for an ASP flood by ammonia with all the inherent logistical advantages. A minor quantity of sodium carbonate is added to the formulation to specifically precipitate calcium ions.
The Effectiveness of MEOR Permeability Modification Beyond the Well Bore
Authors: Jackson Scott , Fisher John , Fallon Bob , Norvell Joe , Hendrickson Ed
Published: June 2014

Biofilms produced from microbes have been shown to reduce the permeability of high perm streaks which can result in improved sweep efficiency. The rate of permeability modification is very reproducible but can vary depending on the specific treatments used. Our approach has been to inoculate the reservoir with a microbe that under the optimal nutrient conditions will express a biopolymer as a film, reduce the size of pore throats and reduce the apparent permeability. The microbe and the nutrients are tailored to the conditions of each reservoir thus giving MEOR the greatest chance for success. This paper presents data that shows modification of permeability can be accomplished away from the injector well bore by microbial production of a biofilm using a proprietary feed protocol (8). These lab scale experiments show that it is possible to do MEOR without affecting the near well bore region of an injector well. A unique set of slim tube experiments are described and an outline of the experimental procedure is provided. This work is a continuation of tests described in earlier papers (SPE129657, SPE146483 and SPE159128 – references 4, 5 and 6).

The zone of permeability modification was measured in a specially designed hydraulically constrained and segmented slim tube. The permeability was modified in later segments of the slim tube using a proprietary protocol. This demonstrates the ability to modify the permeability and control its placement well beyond the injector well bore where it can have a greater effect and avoid near well bore formation damage. In other tests, this permeability modification was shown to change composite slim tubes with high permeability contrast to a system of slim tubes that showed no permeability contrast.
A Survey of Polymer Flooding in Western Canada
Authors: Renouf G.
Published: June 2014

Polymer flooding is becoming increasingly more common and more successful in western Canada. In the year 2011, western Canada produced over 1,600,000 m3 of oil using polymer flooding. In the statistical study reported here, production, injection, reservoir, and operating data were gathered from 32 polymer floods of heavy and medium oil in western Canada. Success was highly variable. Incremental recovery ranged from 0.5 to 14% of the original oil in place over periods lasting between 1 and 9 years. Half of the polymer floods in the project showed a decline in water cut. Oils of very high viscosity and low gravity—as high as 5,000 mPa-s for dead oil and as low as 15°API gravity — were successfully flooded using a polymer solution.

Operational factors that were most significant to flooding success were injection volumes and rates; inclusion of horizontal wells, in particular injection wells; and water quality. Water quality was a major issue, suggesting that the success of many projects comes down to handling operational issues rather than project concept or design. Polymer integrity and injectivity led to many of the operational difficulties.
ASP Process for Anhydrite-Containing Oil Reservoirs
Authors: Sharma Himanshu , Dufour Sophie , Pinnawala Arachchilage Gayani W. , Weerasooriya Upali , Pope Gary A. , Mohanty Kishore
Published: June 2014

The presence of gypsum or anhydrite in oil reservoirs limits the application of alkali-surfactant-polymer (ASP) flooding using conventional alkalis such as sodium carbonate (Na2CO3) because these alkalis precipitate in the presence of gypsum leading to high alkalinity loss and permeability damage. Sodium metaborate (NaBO2) and ammonium hydroxide (NH4OH) were investigated as possible alternatives to Na2CO3. Batch mixing experiments were performed with these alkalis in the presence of excess gypsum, single phase brine-alkali transport experiments were perfomed in sandstone and carbonate cores containing gypsum, and ASP corefloods were performed in outcrop and reservoirs cores (containing gypsum). Effluent pH and ion concentrations including boron, calcium and sulfate were measured using an ion chromatograph (IC) and inductively coupled plasma (ICP). The residence times in injection experiments were increased up to 15 days to study the effect of reaction kinetics. NaBO2 and NH4OH were found to maintain and propagate a high pH of more than 10 in the batch and transport experiments without significant permeability changes. High oil recoveries were obtained in the ASP corefloods along with low surfactant retention due to the high pH propagation.
Influence of Chemical EOR on Topside Produced Water Management
Authors: Argillier J-F. , Henaut I. , Noik C. , Viera R. , Roca Leon F. , Aanesen B.
Published: June 2014

As a result of the recent increases in crude oil prices, a number of chemically-based enhanced recovery methods are being reconsidered by companies around the globe. But one important aspect that is generally neglected in chemically-based enhanced recovery technology concerns the impact of the EOR chemicals on the produced water cycle. This includes the compatibility of EOR chemicals with the additives used to pre-treat the injected water and to process the produced oil/water mixture after EOR chemical breakthrough. Some chemicals themselves, like surfactants and mechanically degraded polymers, may as well produce stable W/O or O/W emulsions and induce strong impact of produced water treatments, that ask for specific additives and equipment in order to keep the topside processing efficient. All these problems may seriously impact the forecast economical performance of EOR projects.

In this paper we will describe in more detail some specific constraints in terms of water management linked to chemical EOR and what are the challenges associated with backproduced chemicals (polymers & surfactants) on topside surface processes. Results will be described using a specific laboratory methodology designed to study the impact of ASP-type chemicals on water treatment efficiency, mimiking actual surface processes, that includes bottle test, gas flotation using an induced gas flotation lab column and membrane filtration. Influence of back produced polymer and surfactants is evaluated by monitoring the turbidity of the water and concentration of oil in water as a function of time.

As the present trend is to increase the use of enhanced recovery methods, among them the chemically-based ones, the industry urges for viable solutions to implement those methods while accomplishing the strict process and environmental constraints that nowadays exist. Water management is an important challenge for chemical EOR that needs an integrated approach and should be studied upfront.
Compositional Modeling of EOR Process in Stimulated Shale Oil Reservoirs by Cyclic Gas Injection
Authors: Wan Tao , Meng Xingbang , Sheng James J. , Watson Marshall
Published: June 2014

Cyclic gas injection is considered as an effective and quick responding recovery process that has been widely used in the worldwide. Studies showed that cyclic gas injection combined with modern technologies such as horizontal well drilling and hydraulic fracturing has achieved promising results in low permeability formation. Cyclic gas injection technique was introduced in our earlier publication for improving oil recovery in stimulated fractured shale oil reservoirs. In this paper, we focus on the effect of injected gas composition and fracture properties on oil recovery. Different injection gas scenarios such as lean gas, rich gas and CO2 were included in the simulation in order to analyze the EOR mechanisms of vaporizing, condensing or a combined condensing/vaporizing process.

Our simulation results indicate that the stimulated natural fractures are critical to enhancing oil recovery and well productivity performance in shale oil reservoirs. Since the interaction of the induced hydraulic fractures with pre-existing natural fractures and fissures makes the hydraulically fractured reservoir modeling very challenging in shale oil/gas reservoirs, we can use a dual-continuum model by making changes to the fracture permeability and intensity to attain a better characterization of the natural fractures. We conclude that cyclic gas injection in shale oil reservoirs employing hydraulically stimulated fractures is feasible to improve substantial amounts of oil production than primary production.