bluuebunny/crossref_metadata_2025 huggingface dataset:
A Novel Low Tension Foam Flooding for Improving Post-Chemical-Flood in Shuanghe Oilfield
Authors: Tang Shanfa , Tian Lei , Lu Jun , Wang Zhengxin , Xie Yunlong , Yang Xiaopei , Lei Xiaoyang
Published: June 2014

Shuanghe oil field is a sandstone reservoir characterized by high water cut, poor sweep efficiency, and high heterogeneity with a long history of water flooding. The field has completed polymer flooding and is now under SP flooding. Although the SP flood is close to the end, the residual oil saturation is estimated to still be about 46~50% OOIP. Therefore, it is desired for future development of such reservoir to find an efficient method to recover residual oil. In this paper, we presented a new high-temperature resistant nitrogen foam system that gives a low oil/water interfacial tension and improves the sweep efficiency after SP flood.

A novel high activity foam agent was prepared with unique surfactants and a high-temperature resistant foam stabilizer. This foam formulation is also able to lower the oil-water interfacial tension to the order of 10-2mN/m and create stable foam at high reservoir temperature. Firstly, the concentration of the foam agent was determined by interfacial tension and foam property. Then, the molecular weight and concentration of foam stabilizer was optimized by Ross-Miles method. Next, the properties of foam formulation were measured by Ross-Miles method at different temperatures, salinities, contents of Ca2+/Mg2+, aging time. The final optimal foam formulation is 0.35 wt% foam agent and 0.1 wt% foam stabilizer, which has a low IFT (5.31×10-2mN/m) and high foam stability index (>10000mLmin). Operating parameters such as foam injection modes, gas liquid ratio, injecting slug size were investigated at reservoirs conditions. The results reveal that, co-injection of gas and solution is a better option than alternating injection; the optimum gas-solution ratio is 1.5:1 by co-injection; the optimum foam injecting size is 0.5 pore volumes; and the injection rate was optimized as well.

The foam flood performance was validated by comparing with other three EOR processes in a series of four oil displacement experiments. The four individual core floods are foam, polymer, gel and SP floods, and they were all injected after water flood. Among these four core floods, foam flood showed the best performance and highest oil recovery. An additional core flood was also done to mimic the field processes. The core was first water-flooded, polymer-flooded and SP-flooded, and then the foam was injected. The results showed the foam flood can effectively recover residual oil after the previous chemical processes. All the experimental results indicate this low-tension foam flooding could be a potential application in Shuanghe oil field.
Modeling of Viscous Displacement in Dual-Porosity Naturally Fractured Reservoirs: Application to Surfactant Enhanced Oil Recovery
Authors: Kiani Mojtaba , Alamdari Baharak B. , Kazemi Hossein
Published: June 2014

Surfactant-enhanced oil recovery (EOR) in fracture-dominated naturally fractured reservoirs (NFR) and very low-permeability Bakken type reservoirs is less known. Therefore, to predict its performance, improvement of the reservoir simulation tools is necessary to account for the surfactant flow mechanisms as much as possible. We present an improved dual-porosity (DP) numerical simulation model and algorithm in which matrix-fracture fluid transfer function was enhanced by implementing a proper viscous displacement mechanism. This mechanism was added to the existed fluid expansion, gravity drainage, and capillary pressure mechanisms. Current DP reservoir simulators generally do not account for the viscous displacement mechanism. To validate both the accuracy and efficacy of the improved model, results were compared with the results from a variable permeability-porosity, single-continuum, fine-grid model.

Simulation results of improved model were in agreement with the results of the fine-grid model as the reference case. In a one-dimensional numerical model, water flood cumulative oil production increased about 5% compared to the conventional DP model. Also, incremental oil production increased over 5% for 1 to 2 wt% surfactant concentrations. Similar results were obtained in multi-dimensional numerical models. In a representative matrix block, the water flood oil production rate started at 0.25 bbl/day in improved model compared to 0.053 bbl/day in conventional DP model. This rate was 0.124 bbl/day versus 0.03 bbl/day at the start of chemical injection. The improved model is computationally very efficient and is much faster than the fine-grid model.

For a practical application, the improved model was used to design and assess the viability of an EOR pilot-test using a single-well, multiple-completion protocol in a fractured carbonate reservoir. This reservoir has a matrix permeability of 10 md and matrix porosity of 0.05, and fracture permeability of 10,000 md. Similar result was obtained using improved and fine-grid models. Also sensitivity analysis was performed on fracture spacing of 5 to 20 ft. We found that smaller matrix blocks are affected more by viscous displacement.
Transport of Nanogel through Porous Media and Its Resistance to Water Flow
Authors: Almohsin Ayman , Bai Baojun , Imqam Abdulmohsin , Wei Mingzhen , Kang Wangli , Delshad Mojdeh , Sepehrnoori Kamy
Published: June 2014

The application of nanoparticles in enhanced oil recovery (EOR) continues to gain attention in the oil industry due to its apparent potential. However, previous studies have focused on the evaluation of stiff particles, such as silica and aluminum oxide. In this paper, we present our experimental results of deformable nanoparticle transport behavior through porous media. Nanogel particles with sizes ranging from 100–285 nm were used to represent deformable nanoparticles. Core flooding tests were run using sandstone cores with water permeabilities ranging from 42 to 1,038 mD. We investigated the effects of the permeability, particle concentration, particle deformability, and flow rate on the particle propagation, resistance factor, and residual resistance factor (permeability reduction factor). The results show that the resistance factor ranged from 5 to 14 for rocks with permeabilities higher than 311 mD, indicating that the nanoparticles were able to transport easily through these rocks. However, the resistance increased to 383 when the permeability was as low as 41.2 mD, indicating that the nanogel could not penetrate the rock easily. After placing the particles, brine was injected at different flow rates. The results indicate that the nanoparticles effectively reduced the permeability of the rocks with the original permeabilities of 143 to 555.4 mD, but the residual resistance factor of the high-permeability rock (1,038 mD) was relatively small, ranging from 2.67 to 4.39. The resistance factor and residual resistance factor increased with the particle concentration and decreased with the flow rate, and both factors can be well fitted using power law equations as a function of velocity. The nanogel adsorption layer thickness decreased with the shear rate.
Estimation of Oil Production Rates in Reservoirs Exposed to Focused Vibrational Energy
Authors: Jeong Chanseok , Kallivokas Loukas F. , Huh Chun , Lake Larry W.
Published: June 2014

Elastic wave-based enhanced oil recovery (EOR) is being investigated as a potential EOR method, since strong wave motions within an oil reservoir - induced by earthquakes or artificially generated vibrations - have been reported to improve the production rate of remaining oil from existing oil fields. To date, there are few theoretical studies on estimating how much bypassed oil within an oil reservoir could be mobilized by such vibrational stimulation. To fill this gap, this paper presents a numerical method to estimate the extent to which the bypassed oil is mobilized from low to high permeability reservoir areas, within a heterogeneous reservoir, via wave-induced cross-flow oscillation at the interface between the two reservoir permeability areas.

This work uses the finite element method to numerically obtain the pore fluid wave motion within a one-dimensional fluid-saturated porous permeable elastic solid medium embedded in a non-permeable elastic semi-infinite solid. To estimate the net volume of mobilized oil from the low to the high permeability areas, a fluid flow hysteresis hypothesis is adopted to describe the behavior at the interface between the two areas. Accordingly, the fluid that is moving from the low to the high permeability areas is assumed to transport a greater volume of oil than the fluid moving in the opposite direction.

The numerical experiments were conducted by using a prototype heterogeneous oil reservoir model, subjected to ground surface dynamic loading operating at low frequencies (1 to 20 Hz). The numerical results suggest that a substantial amount of oil could be mobilized via the elastic wave stimulation. It is also observed that certain excitation frequencies are more effective than others in mobilizing the remaining oil. We remark that these amplification frequencies depend on the formation's elastic properties.

The numerical simulations show that wave-based mobilization of bypassed oil in a heterogeneous oil reservoir is feasible, especially when combined with another EOR method, such as wettability alteration by low-concentration surfactant injection. The extension of this research into a more realistic three-dimensional reservoir model would help determine the optimal locations and frequencies of wave sources.
Right-Sizing the Jay/LEC Field – Commercial 30 Year EOR Project
Authors: Meister Travis , Valenti Nick , Geiger Paul , Townsend Mark
Published: June 2014

Major oil field facilities are designed to optimize on economic performance, which in turn is strongly driven by reserves and peak plateau production rates. However, at late-life conditions these major fields are producing at levels that may no longer merit elaborate facilities and accompanying operating costs. This point was reached in 2008 for the Jay/LEC field (referred to as the Jay field in this paper) that straddles the Florida/Alabama state line, with the field office located 40 miles north of Pensacola in Santa Rosa County, Florida.
A Novel Method of Forecasting CO2 Flood Performance for Various WAG Injection Schemes by Analyzing Injection Pulses
Authors: Liu Shunhua , Sahni Vinay , Hsu Chia-Fu
Published: June 2014

This paper presents a new method for generating dimensionless CO2 flood forecast prototypes for various injection schemes from an existing prototype. Given an existing prototype, the method described in this paper can predict an appropriate prototype for an alternating injection schedule. This methodology enables engineers to quickly generate forecast prototypes by analyzing the oil/gas production response from breaking down existing prototypes (developed either from simulation or from analog field performance) into injected CO2 pulses. A Microsoft Excel with VBA program (PULSER) based on this methodology has been successfully utilized to generate the prototypes for the fluid streams forecast of several West Texas/New Mexico CO2 flooding projects. When compared to reservoir simulation, the Pulse method is much faster in generating new prototypes and more flexible in accomodating different injection scenarios. The results from this method, full field simulation, and blind testing actual field data are remarkably consistent.
Negative Flash for Calculating the Intersecting Key Tie-lines in Multicomponent Gas Injection
Authors: Yan Wei , Michelsen Michael L. , Stenby Erling H.
Published: June 2014

Gas injection is a widely used enhanced oil recovery method and its application is expected to increase due to the high oil price and the need for sequestering carbon dioxide. In order to build a method of characteristics (MOC) solution to a two-phase gas injection system, we need to construct the composition path from the injection gas to the initial oil where all the intersecting key tie-lines must be identified. Calculation of these intersecting tie-lines requires a series of special negative flashes, which allow not only phase fractions outside the physical interval [0, 1] but also negative feed compositions. The phase compositions from one negative flash are used to recombine the feed for the next negative flash. Despite the apparent complexity due to multicomponent equilibrium and transport, for pure component gas injection, negative flash and elimination of components can be performed in an alternating manner. In particular, if the K-values are constant, there exists a simple feature that the vapor fraction roots (β-roots) for the Rachford-Rice equation for the initial oil are the roots to be found in all the negative flashes involved. This leads to a simple and well-structured algorithm for the solution at constant K-values. A unique problem with pure component gas injection is that there could be two possible roots in the β-interval of interest. But if the component to be eliminated is left with an infinitesimal amount, only one of them can still give non-negative phase compositions and thus should be selected. For multicomponent gas injection at constant K-values, we further prove that in addition to the invariant β-roots in the solution procedure, the λ-values for constructing the feeds are simply the vapor phase fraction roots for the injection gas. By solving two negative flashes for the initial oil and the injection gas, we can readily determine all the intersecting tie-lines at constant K-values.
A Novel, Field-representative Enhanced Oil Recovery Coreflood Method
Authors: Gupta Robin , Lu Pengbo , Glotzbach Rodney , Hehmeyer Owen
Published: June 2014

This study describes a new method that can improve laboratory determination of enhanced oil recovery (EOR) potential for a test fluid relative to a base fluid. The new method uses a modified steady-state fractional flow method to measure the shift in oil saturation in a rock at an intermediate fractional flow when changing from a base brine to a test EOR brine(s). This study uses fractional flow analysis and simulations to illustrate the new method and compare with the conventional unsteady-state approach. Through case studies, this work demonstrates that the conventional unsteady-state approach can under or overestimate EOR brine performance due to poor test design or limitations of the conventional method. The proposed method addresses these limitations. The study also discusses how to determine optimal values of fractional flow and total flow rate, both of which are critical test parameters for the new method.
Improving Sweep Efficiency In An Underpressured Naturally Fractured Reservoir
Authors: Montoya J. M , Sandoval R , Vargas A , Cabrera F. C. , Romero J. L. , Muñiz G
Published: June 2014

The Guando field is a late Cretaceous sandstone with two distinct reservoirs with total gross thickness of approximately 1300 feet. Discovered in 2000, the field is Colombia's largest oil discovery since the mid 1980's. Due to the low initial reservoir pressure, water injection began almost simultaneously with field development. Water is injected selectively into the main reservoir's main sands in order to optimize the distribution of injected water. However, oil recovery efficiency is challenged by reservoir heterogeneity, including natural fractures.

The first polymer gel conformance application in Colombia was implemented in 2008 in an effort to improve waterflood sweep efficiency. The objective of the gel treatments was to reduce the permeability in the most conductive natural fractures of the lower layer, ARIN formation. The conformance pilot included two non-adjacent patterns. Initially, the design team considered isolating the upper reservoirs and treating only the lower reservoirs. The treatment designs included several stages of varying gel concentrations and injection rates, which were modified in the course of each treatment application based on surface pressure response.

Post treatment oil response occurred within approximately two months and payout was achieved in less than ten months, driving new candidate selection and treatment in 2013. The paper will discuss the reservoir diagnostics that led to the selection of polymer gel as the most effective solution to severe water channeling. Also, we will present plans for additional gel treatments with an emphasis on cost reduction and improved treatment designs.

Polymer gels have been successfully applied in naturally fractured reservoirs for almost two decades, however, reservoir characterization tools continue to evolve, providing more precise diagnostics that offer improved conformance treatment designs. This case history will provide an updated framework for operators considering chemical sweep improvement technologies as part of an integrated field management strategy.
Long-Term Linear Flow Analysis: Finding Infill Sweet Spots in Underperforming Oil and Gas Fields
Authors: Stright D. H. , Bottjer R. J.
Published: June 2014

A case study will highlight the redevelopment of the Hornbuckle Sussex Field in Wyoming. After discovery in 1984 this oil field was developed on primary production with hydraulically fractured vertical wells. Following an initial steep decline in production the wells exhibit late time modest declines at marginally economic rates. In 2005, Hornbuckle field was generally believed to be depleted on primary production and lOR was not considered to be an option because of failed or underperforming waterfloods in neighboring fields.

Production analysis indicated the presence of long-term linear flow from Hornbuckle wells lasting more than 15 years. This flow regime indicates the presence of geologically-controlled high aspect ratio drainage volumes related to permeability anisotropy/connectivity issues. This is an inefficient drainage process which can result in low recovery factors and lead to further opportunities for infill drilling.

Geological and engineering studies were performed to investigate the feasibility of horizontal well drilling in this field. The paper will show the data mining aspects which identified the opportunity as well as the more detailed analysis that ultimately lead to horizontal well drilling and multi-stage fracturing beginning in 2006. Finally, available horizontal well production performance will be reviewed. Since 2006, field oil production rate has increased more than 25-fold and cumulative oil production has doubled. Redevelopment with horizontal wells is ongoing. The net result is a clear methodology to identify underperforming fields and assess opportunities for redevelopment.
Impact of Salt Diffusion on Low-Salinity Enhanced Oil Recovery
Authors: Brodie James , Jerauld Gary
Published: June 2014

Low-salinity water flooding is an emerging EOR technique that has yielded significant incremental oil in core floods and single- and inter-well trials. Because low-salinity water flooding involves reducing salinity to a low level, of the order of 1000 ppm, there is a risk that its efficiency could be reduced by mixing between injected low-salinity water and high-salinity in situ water held in shales. This risk is more significant when the in situ salinity is very high and the amount of water held in shale is large, as is the case in some reservoirs found in deep-water depositional environments.

To investigate the effect of salt diffusion on low-salinity EOR, low- and normal-salinity (sea water) water floods were simulated in fine-scale, 2D models of deep-water reservoirs incorporating dispersive and diffusive mixing of injected and in situ water and the wettability change caused by low salinity. In the model, dispersion predominates in sandstone, whereas diffusion controls the transport of salt ions within shale. The dispersivity and diffusion coefficients are based on published data.

The simulation results show that low-salinity water-flooding of thin (<2.4m thick) sand layers sandwiched between thick shales is vulnerable to salt diffusion at practical flood rates when the in situ salinity is high (e.g. ≥100,000 ppm). In such layers, diffusion can reduce low-salinity EOR by more than 90%. In the reservoir models we studied, diffusion can reduce the overall low-salinity EOR to 60 – 95% of the value calculated when diffusion is neglected. The adverse effect of diffusion increases as the average sand layer thickness decreases. In thick, channel sands, salt diffusion has only a small effect. Apart from reservoir description, the most important controls on the effect of salt diffusion are intra-reservoir shale diffusivity and in situ salinity.

The simulation results were used to calibrate a simple model for rapidly screening stratified reservoirs. The screening model calculates a ‘diffusion recovery factor (RF) multiplier’ which can be used to discount conventional low-salinity EOR predictions that neglect salt diffusion. The screening model matches simulation data to within 14% RMSE.
Low Salinity Waterflooding at West Salym: Laboratory Experiments and Field Forecasts
Authors: Suijkerbuijk B. M. , Sorop T. G. , Parker A. R. , Masalmeh S. K. , Chmuzh I. V. , Karpan V. M. , Volokitin Y. E. , Skripkin A. G.
Published: June 2014

Low Salinity Waterflooding (LSF) is a rapidly emerging IOR/EOR technology that improves oil recovery by lowering the injection water salinity. A membrane-based desalination process provides additional advantages such as reduction of souring, scaling and it can prevent injectivity decline. Proper screening of LSF for a particular field requires performing laboratory SCAL tests to (i) measure relative permeability curves to enable field-scale quantification of the LSF benefits by modeling and (ii) de-risk the potential of formation damage through clay swelling and deflocculation.

Salym Petroleum Development (SPD; JV Shell/GazPromNeft) is actively looking into IOR/EOR methods to increase the water flood recovery factor. While ASP is being matured as the main EOR option, several LSF laboratory tests have been performed recently to assess the potential of this technique for West Salym. A key LSF enabler in the area is the presence of large, relatively low-saline aquifers in the vicinity of the field, which can serve as a plentiful source of low salinity (LS) injection brine.

This study focuses on the initial Salym LSF SCAL tests performed at reservoir conditions, using representative reservoir core and crude oil, with synthetic brines that reflect the formation and injection water compositions accurately. The experiments comprised a suite of Amott and coreflood tests, following the internal Shell LSF protocol. The tests clearly show a positive LSF effect, with additional oil produced in absence of formation damage. The data indicates that LSF causes a shift in wettability towards a more water-wet behavior, and results in a reduction of Sorw. Upscaling the core flood results to field scale indicated that incremental recoveries within the life time of the field could be 1.7% of oil initially in place (OIIP) in tertiary mode, while a secondary mode LSF scheme would have increased the oil recovery over the same time by almost 4% of OIIP.
Streamline-based Transport Tomography Using Novel Tracer Technologies
Authors: Kam D. , Datta-Gupta A.
Published: June 2014

Traditional history matching involves calibration of reservoir models using well response such as production or tracer data aggregated over multiple producing intervals. With the advent of novel tracer technologies, we can now obtain distributed water or tracer arrival time information along the length of horizontal or vertical wellbores. This provides significantly improved flow resolution for detailed reservoir characterization through inversion of distributed water or tracer arrival times in a manner analogous to travel tomography in Geophysics.

In this paper, we present an efficient approach to incorporate novel tracer surveillance data and distributed water arrival time information during history matching of high resolution reservoir models. Our approach relies on a novel streamline-based workflow that analytically computes the sensitivity of the arrival time with respect to reservoir heterogeneity, specifically porosity and permeability variations. The sensitivities relate the changes in arrival time to small perturbations in reservoir properties and can be obtained efficiently using the streamline-based approach with a single flow simulation. This makes the approach particularly well-suited for high resolution reservoir characterization. Finally, the sensitivities are used in conjunction with an iterative inversion algorithm to update the reservoir models using existing and proven techniques from seismic tomography.

The power and utility of our proposed approach is demonstrated using both synthetic and field examples. These include the SPE benchmark Brugge field case and a tracer test at the Hill Air Force Base, Utah. Compared to traditional history matching techniques, the proposed tomographic approach is shown to result in improved resolution of heterogeneity through matching of water arrival time at individual completions in addition to the aggregated well production response. This results in improved performance predictions and better identification of bypassed oil for infill targeting and EOR applications.
A Simple Technique to Determine the Strength of Millimeter-Sized Particle Gel
Authors: Muhammed Farag A. , Bai Baojun , Al Brahim Ali
Published: June 2014

Millimeter-sized superabsorbent polymers (SAPs), also called preformed particle gels (PPGs), are gaining attention and popularity for use in conformance-improvement treatments. The strength of PPGs is important to the optimization of their performance as plugging agents. Conventional gel strength has always been measured by applying load to single, isolated sample with certain geometry. However, determining the strength of sugar-like PPGs with irregular shapes is a challenging task. Previous publications have proposed different methods to evaluate gel strength. However, those methods are not suitable for rapid quantitative evaluation of PPG strength on site. We designed a simplified experimental apparatus to evaluate gel strength in the laboratory or on site during gel treatment. It consists of a positive displacement hand pump and a specially designed piston accumulator. The top cap of the accumulator has a hole connected to the pump by tubing and fittings. The bottom cap is a stainless steel screen plate with multiple holes. During the experiments, we placed swollen PPG on top of the screen plate and below the piston, gradually increasing the pressure to push the piston until gel particles passed through the plate holes. The minimum pressure needed to push gel particles out of the holes was considered as the threshold pressure of a gel particle moving through a pore throat, which provides quantitative indication of the gel strength. The apparatus also can be used to evaluate gel rheology in terms of its apparent viscosity as a function of the shear rate. We observed that the PPGs are prone to stiffen as the brine salinity increased which caused the threshold pressure to increase. Also the PPGs threshold pressure depended chiefly on the brine salinity, the screen hole size, and the holes density per screen plate. Additionally, the PPGs threshold pressure correlated excellently with their elastic modulus which was measured using a rheometer. PPGs injection pressure did not increase significantly with the injection rate. This behavior is consistent with the real-time injection pressure and injection rate change which has been often observed during PPG treatments in oilfields. This method can serve as a simple, fast, and practical technique to quantitatively evaluate particle gel strength in the laboratory and on site during a PPG treatment process.
Rapid Analysis of Tracers for Use in EOR Flood Optimization
Authors: Sharma Abhinav , Shook G. Michael , Pope Gary A.
Published: June 2014

Tracer testing is a powerful tool for reservoir surveillance. Conducting and analyzing an interwell tracer test before starting an EOR flood provides the specific information required to balance the pattern's swept pore volume and optimize chemical or solvent use. Tracer testing also plays an important role in EOR by establishing a baseline for estimating incremental volume swept and recovery factor.

A key limitation to tracer testing is the time required to obtain a complete interpretation of the test results. Conventional interpretation methods require observing exponential decline in the tracer concentration from all producers; depending on the pattern size and processing rate, this can take many months or years. Meanwhile, the EOR flood is delayed, thereby eroding its value and reducing the remaining oil target. We have developed a method for analyzing tracer data from relatively early times based in part on a new way to extrapolate the tracer data, providing timely information to optimize flood performance. The extrapolation can be done shortly after the peak concentration is observed in the well with the slowest response. We illustrate the extrapolation procedure using a synthetic yet realistic dataset showing that the new methods result in a good approximation at much earlier times. We then compare swept pore volumes using early time data with the (correct) swept pore volumes using the complete tracer dataset. We also discuss how early time approximations can thus provide the opportunity to optimize chemical flood performance and field start-up of EOR floods in a timely fashion.
A Laboratory Study to Investigate CO2 Potential to Mobilize Paleo Oil
Authors: Aleidan Ahmed A. , Zhou Xianmin , Kwak Hyung , Kokal Sunil
Published: June 2014

All reservoirs contain a transition zone below the oil water contact (OWC) which varies in thickness depending on the reservoir rock properties. In some reservoirs that have undergone geological and hydrodynamic titling, there could be an additional, sometimes significant, residual oil zone (ROZ) below the transition zone. This zone sometimes referred to as the ‘paleo’ oil zone and may contain significant quantities of hydrocarbons. Traditionally, this has not received much attention as its oil is immobile and does not normally produce through primary and secondary recovery methods. However, paleo oil has the potential to be mobilized by CO2 injection.

The objective of this study is to show the ability of CO2 injection to mobilize paleo oil in the ROZ. Different laboratory experiments on actual reservoir sponge cores from wells intersecting the ROZ have been conducted at reservoir conditions. The study includes static CO2 saturation (PVT cell) and dynamic CO2 coreflooding experiments, and Nuclear Magnetic Resonance (NMR) analysis. The mobility of paleo oil by CO2 flooding was investigated using both static and dynamic CO2 injection experiments on sponge cores containing paleo oil. The static experiments showed, through images and videos, how the CO2 can mobilize the paleo oil in the cores. The coreflood experiments showed the potential to mobilize the original oil in cores from these two wells intersecting the ROZ. It was found that CO2 soaking is a critical factor to mobilize oil because it allowed more time for the CO2 to interact with the available components. Core samples were further analyzed microscopically using NMR analysis (before and after CO2) to complement coreflood interpretations. NMR showed the exact places in the core where the oil was mobilized by CO2 and the type of components extracted after the experiments (mostly intermediate).
Full-Field Simulation and Optimization Study of Mature IWAG Injection in a Heavy Oil Carbonate Reservoir
Authors: Bender Serdar , Yilmaz Mustafa
Published: June 2014

Bati Kozluca Field is a heavy oil carbonate reservoir discovered in 1985; it is located in the South East of Turkey, close to Syria border. The reservoir began primary production in 1985, developed with 41 wells producing 12.6 API oil. Main constraints for oil recovery are the low aquifer support, low solution gas oil ratio and high oil viscosity which is 480 cp at reservoir conditions. In order to increase 5% recovery, full field continuous immiscible CO2 injection had been implemented from 2003 to 2007 and full field IWAG injection had been implemented from 2007 to 2012. These projects increased the oil recovery from 5% to 6.7% and increased the daily oil production two times. In 2012, it was decided to re-develop the field to increase the 6.7% recovery.

This paper first gives the results of the CO2 and IWAG applications in the Batı Kozluca Heavy Oil Field and then describes the field-wide simulation study conducted to predict the future reservoir performance of the black oil simulation model under various operating and development strategies. First, available data is screened and quality of the data is evaluated; then, dynamic model is built. The model has been successfully history matched with 27 years of production, injection, saturation and pressure history on both the field and the well scale. The history matched model is used to decide the methodology and to determine the infill well locations, injection pattern and injection schemes to increase the oil recovery. Simulation results show that recovery can be increased from 6.7% to 9% with the current injection pattern and without any investment by continuing the project with the optimized injection parameters. However, injection pattern needs to be modified to increase the volumetric sweep efficiency and oil recovery.
Frontal Stability Analysis of Surfactant Floods
Authors: Tavassoli Shayan , Pope Gary A. , Sepehrnoori Kamy
Published: June 2014

Recent surfactant flooding experiments have shown very efficient oil recovery can be obtained without mobility control when the surfactant solution is injected below the critical velocity required for a gravity-stable displacement. The purpose of this study was to develop a method to predict the stability of surfactant floods at the reservoir scale based on gravity-stable surfactant flooding experiments at the laboratory scale. The scale up process involves calculation of the appropriate average frontal velocity for the reservoir flood. The frontal velocity depends on the well configuration. We have performed systematic numerical simulations to study the effect of key scaling groups on the performance of gravity-stable surfactant floods. We simulated three-dimensional heterogeneous reservoirs using a fine grid and a third-order finite-difference method to ensure numerical accuracy. These simulations have provided new insight into the behavior of gravity-stable surfactant floods and in particular the importance of the microemulsion properties. The capability to predict when and under what reservoir conditions a gravity-stable surfactant flood can be performed at a reasonable velocity is highly significant. When a surfactant flood can be done without polymer (or foam) for mobility control, cost and complexity are significantly reduced. Advantages are especially significant when the reservoir temperature is high and the use of polymer becomes increasingly difficult. Our simulations show that gravity-stable surfactant floods can be very efficient using horizontal wells in reservoirs with high vertical permeability.
Alkaline Surfactant-Polymer Formulation Evaluation in Live Oil Conditions: The Impact of Temperature, Pressure and Gas on Oil Recovery Performance
Authors: Oukhemanou Fanny , Courtaud Tiphaine , Morvan Mikel , Moreau Patrick , Mougin Pascal , Féjean Christophe , Pedel Nicolas , Bazin Brigitte , Tabary René
Published: June 2014

An Alkaline-Surfactant-Polymer / Surfactant-Polymer (ASP/SP) design study generally includes intensive work. Hundreds formulations have to be tested to screen phase behavior and typically a dozen of corefloods are performed to select the best formulation and further optimize the injection strategy/slugs design to match economic criteria.

To be extrapolated to the field, it is critical to perform these tests in conditions as close as possible to real reservoir conditions: reservoir temperature, injection brine, reservoir pressure and reservoir oil. Specifically, dissolved gas and high-pressure tend to significantly impact crude oil properties, and subsequently formulation behavior and performance, even when limited amount of gas is present. Ideally, this parameter should be considered from the beginning of the formulation design. However, considering the high number of tests to perform, as well as the relatively high cost and technical challenges associated with live oil experiments, it is unrealistic to routinely perform all the required experiments in high-pressure environment.

We will present here the methodology developed to design surfactant based process by mimicking the impact of reservoir gas and pressure on the reservoir stock-tank oil.

First a thermodynamic model based on an equation of state is fitted to reservoir PVT data (Gas/Oil Ratio or GOR, stocktank oil and associated gas composition analysis, bubble pressure and volumetric factor Bo) to predict consistent thermodynamic behavior and properties of the live oil. This step allows us to validate the reservoir conditions. A recombination of stock-tank oil with gas should be then performed to obtain the fluid in the reservoir conditions. Then we will illustrate through case studies how to combine a high-throughput robotic platform and a high-pressure/high-temperature cell to determine a representative crude oil matching live oil main properties, namely viscosity and Equivalent Alkane Carbon Number (EACN). This representative crude oil is obtained from the reservoir stock-tank oil which has been adjusted, using solvents or alkanes, to present the same characteristics as the reservoir live oil. This oil will therefore be used for an exhaustive formulation design and process optimization. Finally, we will compare oil recovery performances with the representative crude oil and with the reservoir live oil.
Reservoir In-Depth Waterflood Conformance: An Offshore Pilot Implementation
Authors: Choudhary M. , Parekh B. , Solis H. , Meyer B. , Shepstone K. , DeZabala E. , Prostebby C. , Manrique E. , Izadi M. , Larsen D.
Published: June 2014

Ebano field is a high permeability slope-channel turbidite reservoir located offshore Equatorial Guinea, West Africa. Oil production from this field started in May 2009 and water injection began in July 2009. Currently, the field operates with two wells; one injector and one producer with a well spacing of 1.5 km. Water breakthrough was observed approximately one year after water injection began, which was much earlier than the original prediction suggesting presence of water injection thief zone(s). Several reservoir management strategies to improve sweep efficiency were considered for implementation in this field including a reservoir in-depth waterflood conformance technology using a thermally active polymer (TAP).

This paper will summarize the TAP pilot design, implementation, and performance interpretation based on a comprehensive surveillance program. The paper will also describe the workflow utilized to evaluate the technical feasibility of TAP technology (supported by detailed engineering, laboratory, and simulation studies).

Engineering and laboratory studies to evaluate the technical feasibility of TAP started September 2010 and TAP pilot implementation commenced April 2011. Injection of TAP treatment was done from a barge requiring significant coordination between offshore and onshore to ensure safe handling and injection of chemicals. A total of 48,000 bbl of TAP were injected at an injection rate of 6,000 bbl/d, using a concentration of 15,000 ppm (4 cp injected). This treatment has been one of the largest offshore implementation using TAP technology. A detailed surveillance plan was put in place that included gathering and detailed analysis of injection/production data, injection pressure, produced water compositional analysis, production logs (PLT), and Fall-Off Tests (FOT) before and after the TAP treatment.

Ebano pilot results validated TAP displacement and activation away from the injector. PLT data showed that the injection profile remained unaltered post treatment. Time-lapse FOT proved to be very useful in monitoring TAP performance. Uncertainties relating to how far away from the injector TAP was fully activated, injection pressure response (simulation vs. field), and production performance will also be addressed.
Pilot Test of Indigenous Microorganism Flooding in a Heavy Oil Reservoir
Authors: Cui Qingfeng , Yu Li , Dong Hanping , Huang Lixin , Dai Xuecheng
Published: June 2014

Indigenous microbial flooding technology injects nutrients (sometimes mixed with air), activates the useful indigenous microbes which multiply and metabolize rapidly, and oil recovery enhanced. The technology was carried out through in Dagang oilfield in China from 2001 and mostly used in high temperature oilfield. Generally, the technology injects only basic nitrogen source mixed with air and utilizes residual oil in the reservoir as carbon source. Whereas, exgenous microbial flooding tests carried out in the past mostly inject carbon source, nitrogen source and no air.

Based on the research of reservoir geology, the analyses of development situation and study of nutrients, the pilot test was conducted in a low temperature(20°C) heavy oil(80mPa• S) reservoir in a trial block with 4 injection wells and 7 production wells. The test is different from the past MEOR tests in injecting molasses as carbon source, nitrogen source and air at the same time. It injected 0.05 pore volume and lasted for 2 years.

Field performance monitoring and product ion tracking results show: ① the indigenous bacteria were activated with the number increased 2-3 orders compared with pre-test, and microbial population structure changed apparently; ②properties of formation water were changed, the content of HCO3- in formation water varied greatly, and emulsion was found; ③Although CO2 can be generated when molasses is decomposed and activity of producing methane was strengthened, the content of CO2 and CH4 in the gas of oil well changed slightly; ④oil produc increased in wells, and total oil increase was 5, 626t up to Jun., 2013. ⑤That the crude oil is emulsified by microbes is the primary mechanism of Indigenous Microbial Flooding Technology and that biogas generated by microbes is not the primary mechanism were determined.

Indigenous Microbial Flooding Technology injecting organic carbon source, nitrogen source and air simultaneously was appiled successfully in a low temperature heavy oil reservoir, which would serve as an example for similar reservoirs in high water cut stage.
Pilot to Full-Field Polymer Application in One of the Largest Onshore Field in India
Authors: Prasad Dhruva , Pandey Amitabh , Kumar M. Suresh , Koduru Nitish
Published: June 2014

The paper discusses the full-field polymer flood implementation plan post successful pilot result in one of the largest onshore fields in India. Mangala field contains multi-Darcy sandstones that have high porosity and very low connate water saturation and low temperature (65 degC). The connate water salinity is low (~6500 total dissolved solids), The crude is waxy and viscous, which results in unfavorable mobility for water-flooding, Chemical flood was identified as a potential EOR method during a screening study.

A normal 5 spot polymer flooding pilot has been conducted and results are encouraging in terms of additional oil recovery and reduction of water cut. Additionally much has been learnt about how to optimize the surface facility, polymer preparation, and polymer quality monitoring.

Following the successful completion of the pilot, it is planned to implement a polymer flood for the fullfield. All the lab results and pilot learnings have been incorporated to minimize the uncertainty and risks. Different subsurface injection pattern concepts have been evaluated based on the reservoir characteristics. Various parameters like pattern and number of wells, polymer viscosity, tapered vs. fixed concentration, polymer slug sizes and other variables have been optimized and are discussed in the paper. Sensitivities to capture the impact of polymer adsorption, implementation schedule, conformance in injectors, visco-elastic effect of polymer, polymer shear thinning characteristics etc. on recovery have been studied. Learning from pilot has been used in selecting the surface facility, well design, pumping facility, selective completion for conformance control, surface pressure requirement, and designing to minimize the viscosity loss across the completion and sand face.

Surface facilities concepts have been finalized to prepare concentrated polymer at a single location and pumping it to each well for injection. Polymer flooding has the potential to significantly improve the sweep efficiency in the field and to increase expected ultimate recovery (EUR). The project is one of the largest in the world in terms of scale, polymer usage, and related facility and logistics.
Multiple Mixing Cell Method for Three-Hydrocarbon-Phase Displacements
Authors: Li Liwei , Khorsandi Saeid , Johns Russell T. , Ahmadi Kaveh
Published: June 2014

Low-temperature oil displacements by CO2 involve complex phase behavior, where three hydrocarbon phases can coexist. Reliable design of miscible gas flooding requires knowledge of the minimum miscibility pressure (MMP), which is the pressure required for 100% recovery in the absence of dispersion or as defined by slim-tube experiments as the "knee" in therecovery curve with pressure where displacement efficiency is greater than 90%. There are currently no analytical methods to estimate the MMP for multicomponent mixtures exhibiting three hydrocarbon phases. Also, there are no reliable numerical methods to estimate the MMP using compositional simulation largely because of robustness issues of three-phase equilibrium calculations, inaccurate three-phase relative permeability models, and phase identification and labeling problems that can cause significant discontinuities and failures in the simulation results. How miscibility is developed, or not developed, for a three-phase displacement is not well known.

We developed a new multiple three-phase mixing cell method that gives a relatively easy and robust way to determine the pressure for miscibility or more importantly the pressure for high displacement efficiency. The procedure that moves fluid from cell to cell is robust because it is independent of phase labeling (i.e. vapor or liquid), has a robust way to provide good initial guesses for three-phase flash calculations, and is also not dependent on three-phase relative permeability (fractional flow). These three aspects give the mixing cell approach significant advantages over using compositional simulation to estimate MMP or to understand miscibility development. The approach can be integrated with previously developed two-phase multiple mixing cell models because it uses the tie-line lengths from the boundaries of tie triangles to recognize when the MMP or pressure for high displacement efficiency is obtained. Application of the mixing cell algorithm shows that unlike most two-phase displacements the dispersion-free MMP may not exist for three-phase displacements, but rather a pressure is reached where the dispersion-free displacement efficiency is maximized. This is the first paper to examine a multiple mixing cell model where two- and three-hydrocarbon phases occur and to calculate the MMP and/or pressure required for high displacement efficiency for such systems.