bluuebunny/crossref_metadata_2025 huggingface dataset:
A Review on Thermal Enhanced Heavy Oil Recovery from Fractured Carbonate Reservoirs
Authors: Ghoodjani Eshragh , Kharrat Riyaz , Vossoughi Manouchehr , Bolouri Seyed Hamed
Published: June 2012

Heavy oil in Middle East fractured carbonate reservoirs account for 25–30% of the total oil in place in the region. Production of heavy oil from such reservoirs is thought to play an important role in the future of the ever-growing world’s energy consumption in which Iran’s recoverable heavy oil is more than 85 billion barrels. The offshore Ferdows field in Iran is reportedly on the order of 30 billion barrels of oil and holds perhaps the greatest promise to add significant future carbonate heavy oil production within the region.

With depletion of conventional petroleum reserves and increase of hydrocarbon fuel demand, there is no doubt that there will be a tremendous demand on the development of heavy oil reservoirs in the coming decades. Despite its strategic importance, recovery of heavy crude from fractured carbonate reservoirs has found limited applications due to the complexity of such reservoirs. As most of the oil is stored in matrix due to its higher storage capacity than fracture network, reservoir development plans will aim at maximizing the matrix oil recovery. For reservoirs with high recovery factor, minimizing matrix residual oil saturation is a critical issue to extend the life of the reservoir. For reservoirs with low recovery factor, accelerating the production rate is more vital. For each of these reservoir types, different Enhanced Oil Recovery (EOR) methods should be considered and implemented accordingly.

In this study, a comprehensive review is conducted to figure out the feasibility of heavy oil recovery from fractured carbonate reservoirs by use of Cyclic Steam Stimulation (CSS), Steam injection, In-Situ Combustion (ISC), Steam Assisted Gravity Drainage (SAGD), Vapor Extraction (VAPEX) and Expanding Solvent-Steam Assisted Gravity Drainage (ES-SAGD).
Preparation and Performance of Environment-friendly Nanoemulsion with Antiscaling
Authors: Luo Mingliang , Sun Houtai , Jia Zilong , Wen Qingzhi , Liao Lejun
Published: June 2012

Formation scale may be resulted in permeability decrease greatly, especially in low or ultra-low permeability reservoirs. A nanoemulsion with very small particle size, ultra-low interfacial tension and highly penetration possesses good properties in formation antiscaling. The antiscaling ingredient is slowly released from the nanoemulsion, which prolongs the effect time of antiscaling. The colloidal particles are able to quickly and effectively reach the target layer because their sizes are smaller than the rock pore throats. Nanoemulsions also dissolve or disperse big liquid droplets and organic impurities, which may regain rock permeability. In the work, with a green surfactant fatty acid methyl ester sulfonate (MES) and a biodiesel fuel, the optimal formation conditions of MES middle phase microemulsion were obtained by the orthogonal design experiments as follows: CMES = 10.0~12.0g/mL, Cn-butanol=12.0g/mL, CNaCl=6.0g/mL; The effects of concentrations of NaCl and n-butanol, and the type of alcohols on the microemulsion phase behavior, the optimal salinity (S*) and the length of salinity (ΔS) were investigated.

An antiscaling nanoemulsion was prepared by three kinds of antiscaling ingredients FG-1, FG-2 and FG-3 dissolved in water phase. The antiscaling rates of two nanoemulsions with antiscaling ingredients FG-1 and FG-2 are 90.1% and 89.6%, respectively. There are no flocculates contacting with the formation water. The nanoemulsion with FG-2 possesses good adsorption, slow desorption rate and good antiscaling performance under high salinity. Compared to the present scale inhibitors, the antiscaling rate of nanoemulsion has a peak value, which greatly increases the useful effect time of scale inhibitor, and improves the anti-scaling effect and repairs permeability of rock. There is a good prospect for controlling the formation damage in low or ultra-low permeability reservoirs and water-sensitive formation.
Modeling and Simulation of Nanoparticles Transport in a Two-Phase Flow in Porous Media
Authors: El-Amin M. F. , Salama A.. , Sun S..
Published: June 2012

In the current paper, a mathematical model to describe the nanoparticles transport carried by a two-phase flow in a porous medium is presented. Both capillary forces as well as Brownian diffusion are considered in the model. A numerical example of countercurrent water-oil imbibition is considered. We monitor the changing of the fluid and solid properties due to the addition of the nanoparticles using numerical experiments. Variation of water saturation, nanoparticles concentration and porosity ratio are investigated.
Research and Application of Nano Polymer Microspheres Diversion Technique of Deep Fluid
Authors: Tian Yuqin , Wang Lushan , Tang Yanyan , Liu Chengjie , Ma Chao , Wang Tao
Published: June 2012

Nano polymer microspheres are a new oil profile control system, which can be adjusted according to the formation pore throat. After hydration and swelling, the microspheres would reach the designed size and have relatively strong intensity. When the size of the microspheres is bigger than that of the formation pore throat or bridged blockage is formed, reliable blockage can be formed. The microspheres are elastic, which can deform and move forward under certain pressure, so that fluid diversion can be realized step by step and the request of movable agent is satisfied. The microspheres can resist high temperature to 110°C and high salinity to 200000mg/L (Ca2++Mg2+=3000 mg/L). To test its effect, this polymer microspheres technology is used at a serious heterogeneous and high temperature reservoir. The temperature of the test block is 98°C, and the salinity of injection water is 16380mg/L. The average permeability is 932×10‒3μm2, and the permeability contrast is obvious (high permeability is 4μm2, low permeability is 0.8μm2). Therefore, two sizes of microspheres are designed. The combination system of polymer microspheres and surfactant are injected, and the system is divided into five slugs. Double tubes physical modeling experiments are done, and the results show that the block off capacity of this design is competent, increasing oil recovery dramatically. Thanks to the accordant microspheres design and the rational injection design, this polymer microspheres technology has become the effective method for profile control and water plugging to serious heterogeneous and high temperature reservoirs.
Fluorescent Nanobeads: a First Step Toward Intelligent Water Tracers
Authors: Agenet Nicolas , Perriat Pascal , Brichart Thomas , Crowther Nicolas , Martini Matteo , Tillement Olivier
Published: June 2012

Reservoir monitoring is an essential tool to optimize oil production. Among other techniques, water tracers are very useful to understand flow patterns between wells (i) during regular waterflood operations, (ii) for EOR pilot or (iii) field development. This paper focuses on the elaboration of a new family of tracers based on fluorescent silica colloids for in situ real-time optical detection. Indeed, these architectures of nanometric size (nanoparticle diameter controllable between 30-100 nm) permit (i) the encapsulation of fluorescent dyes (the intrinsic signal of tracers) and (ii) a tailored interface with the environment (by specific surface functionalization). Dyes, such as organic molecules and/or rare-earth complexes could be quantified by conventional fluorescence apparatus. The smart incorporation of specific fluorophores of different nature within nanobeads allows multi-coding signal of tracers and therefore the possibility to supervise the properties of reservoir. We demonstrate that silica nanobeads could act as sensitive probes of physicochemical conditions of reservoir (volume, pH, temperature, oil ratio, salt content…), because of (i) their specific fluorescence coding, (ii) the long-term colloidal stability in seawater conditions, and (ii) the adaptable real-time monitoring detection setup. Actually, by the procedure described in this work, we are able to produce theoretically dozens of fluorescence tagging combinations based nanoparticles with suitable surface properties. The possible future utilization of fluorescent nanobeads as traces in well exploitation is also demonstrated by core-flood experiments.
Nanoparticle Transport through Porous Media: Screening Tools for Mobility Prediction
Authors: Zies Camila C. , Zhu Huigang , Avendano Carolina , Colvin Vicki
Published: June 2012

Crude oil production has distinct phases of recovery: primary, secondary, and tertiary. After primary and secondary recovery, up to 60% of the hydrocarbon can still remain in the reservoir, needing more advanced recovery techniques. Nanoparticles and their unique size dependent properties can be engineered in a number of high end technologies for enhanced oil recovery (EOR) applications. Naturally, as the average reservoir depth can go anywhere from 35 meters up to 12 km, it is necessary that the nanoparticles present a reasonable mobility, otherwise, without reaching the area of interest, i.e., oil/ water interface, their use would not be feasible. This work aims to study the interaction of different nanoparticles synthesized by our group with a silica substrate, so as to screen the mobility of the particles. This investigation was done using a Quartz Crystal Microbalance with Dissipation (QCM-D) and an Atomic Force Microscope (AFM), with nanoparticles of varying compositions over a wide range of salinity concentrations, and pHs to understand the role these parameters play in the nanoparticle-surface interaction.
Study of Surfactant-Polymer Flooding in Heavy Oil Reservoirs
Authors: Feng Anzhou , Zhang Guicai , Ge Jijiang , Jiang Ping , Pei Haihua , Zhang Jianqiang , Li Ruidong
Published: June 2012

As the alkali in alkaline-surfactant-polymer (ASP) flooding often causes the difficult problems of scaling and emulsification, surfactant-polymer (SP) flooding was proposed for enhancing heavy oil recovery in China. However, it is difficult to reduce the interfacial tension (IFT) to an ultra-low value without alkali for the traditional chemical system. This paper presents a type of betaine surfactant which has an excellent ability to reduce oil/water IFT at low concentration without alkali, and alkali lignin with low-price was compounded as a sacrificial agent to reduce the adsorption. Finally, sandpack flooding tests were conducted to examine the effectiveness of enhanced oil recovery by compound chemical system containing polymer, betaine and alkali lignin.

The results showed that the IFT reduced to 0.001 mN/m or less at a betaine concentration range of 0.01wt% to 0.1wt% without alkali, meeting the requirements of SP flooding; the dynamic adsorption test showed that of the adsorption amount reduced approximately 40% when the mass-ratio of alkali lignin and betaine was 1 to 7.5; moreover, the polymer added into compound surfactant system accelerated the reduction of the oil/water IFT. Sandpack flooding tests indicated that the injected chemical system containing polymer, betaine and alkali lignin after water flooding could enhance oil recovery by 13%~20%, which was significantly higher than that of polymer flooding under the same conditions.
Pressure Maintenance and Improving Oil Recovery via Water-Alternating-CO2 Process in Thin Heavy Oil Reservoirs
Authors: Zheng Sixu , Yang Daoyong
Published: June 2012

Techniques have been developed to experimentally and numerically evaluate performance of water-alternating-CO2 processes in thin heavy oil reservoirs for the purpose of pressure maintenance and improving oil recovery. Experimentally, a three-dimensional (3D) physical model consisting of three horizontal wells and five vertical wells is used to evaluate the performance of water-alternating-CO2 processes. Two well configurations have been designed to examine their effects on heavy oil recovery. The corresponding initial oil saturation, oil production rate, water cut, oil recovery and residual oil saturation distribution are examined under various operating conditions. Subsequently, numerical simulation is performed to match the experimental measurements and optimize the operating parameters (e.g., slug size and water-CO2 ratio). It has been shown that water-alternating-CO2 processes implemented with horizontal wells can be optimized to significantly improve performance of pressure maintenance and improving oil recovery in thin heavy oil reservoirs. The incremental oil recovery of 12.4% and 8.9% through three water-alternating-CO2 cycles are experimentally achieved for the aforementioned two well configurations, respectively. The excellent agreement between the measured and simulated cumulative oil production indicates that the displacement mechanisms governed water-alternating-CO2 processes have been numerically simulated and matched. The WAG ratios of 0.75 and 1.00 are found to be the optimum values for Scenarios #1 and #2, respectively.
Viscosifying Surfactant Technology for Heavy Oil Reservoirs
Authors: Morvan M. , Degré G. , Beaumont J. , Colin A. , Dupuis G. , Zaitoun A. , Al-Maamari R. S. , Al-Hasmi A. R. , Al-Sharji H. H.
Published: June 2012

Injections of polymer solutions have been used to improve oil recovery in heavy oil reservoirs (Zaitoun et al. 1998). Most of those polymer flood experiences refer to conditions where the polymer solution propagates through the porous media under low shear rate and exhibits mostly a Newtonian behaviour. On the other hand recent publications indicate injection of polymer solutions at concentration larger than conventional polymer flooding can result in higher recovery at field scale. Typically oil recovery of more than 20% OOIP compared to waterflooding has been reported for light oil (Wang et al; 2011). However injectivity issues have to be considered when injecting concentrated polymer solutions. This study examines whether non polymeric elastic fluids derived from surfactant solutions can represent an alternative approach to elastic polymer floods. The technology we have developed matches the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity).

Bulk flow properties as well as rheology in a confined geometry have been used to compare flow properties of surfactant and high molecular weight polymer solutions. The elastic properties of both fluids have been characterized in terms of Weissenberg numbers. The data indicate the surfactant solution as opposed to the polymer one is highly elastic at low shear rates even in the presence of brine. Those results are confirmed by comparative experiments made using a Particle Image Velocimetry (PIV) technique. Injectivity of concentrated surfactant solutions has been tested in single-phase conditions and indicated a good in depth propagation of the fluid. A series of core-flood experiments has been performed using heavy oil reservoir cores. The surfactant slug has been combined with a conventional low-concentration polymer flooding to benefit from surfactant elasticity and improve oil recovery.
A Novel Methodology for Simultaneous Estimation of Gas Diffusivity and Solubility in Bitumens and Heavy Oils
Authors: Saboorian-Jooybari Hadi
Published: June 2012

The most important parameters in the calculation of the rate and extent of gas dissolution during solvent-based heavy oil recovery processes are diffusion coefficient and solubility. However, there is a lack of sufficient experimental data on these parameters. Further, significant differences associated with reported values of diffusivities because of various nonphysical approximations made in development of the models used for calculation of this coefficient from the pressure-decay tests.

This paper presents an inverse solution technique for determining solubility, diffusion coefficient and interface mass transfer coefficient of gases in liquids (bitumens) using pressure-decay data. The approach, which is based on modeling the rate of pressure decline in response to gas diffusion, couples gas mass balance equation with the diffusion equation. Analytical solution for the forward problem is obtained by assigning physically meaningful initial and boundary conditions. Then, the forward solution is utilized to develop an interpretation technique for simultaneous determination of the equilibrium solubility, diffusivity and interface mass transfer coefficient of gas into oil. To evaluate the validity of the proposed technique, literature pressure-decay data of CH4 and CO2 dissolution in Athabasca bitumen at two different temperatures (50 and 90 °C) and initial pressure of 8 MPa were used. The simultaneous estimation of the three mass transfer parameters is the main advantage of the new methodology over the existing ones. Additionally, the calculation method doesn’t depend on empirically-defined unknowns such as Henry’s constant, density of solvent-bitumen mixture and etc. Eventually, the effect of neglecting gas-bitumen interface resistance on the predicted values of gas solubility and diffusivity was investigated.
Gel Treatments Pilot Test in Conventional Heavy Oil Reservoirs of China Offshore Oil Field
Authors: Su Yanchun , Li Yanlai , Tian Lixin , Ma Kuiqian , Wang Lilei
Published: June 2012

More than 80% oil resources were heavy oil in Bohai Bay of China. Generally, we used water flooding in the reservoirs with the viscosity less than 400cp. But there were many challenges during water injection in conventional heavy oil reservoirs because high oil-water viscosity ratio lead quick breakthrough of injecting water. And with the oil-water viscosity ratio increasing, the breakthrough of injecting water became more serious. In order to solve these problems, the gel treatments on the injection wells pilot test were conducted in x oilfield during the year 2009 to 2011. Before pilot test, laboratory study under field conditions was conducted to determine the chemical parameters of the gel. We also did numerical simulation study with CMG. A range of variation of critical parameters was evaluated in the simulation for understanding the gelation process undergroud. The model was used to predict the reservoir response under different chemical parameters. Results from simulation showed that water cut reduction ranged from 15.9 to 36.6% which matched the trends observed in wells. On the other hand, dynamic method was also used to evaluate the gel pilot test. The Hall curve analysis was used to evaluate the effectiveness of the injection well and to calculate the resistance factor (RF) & residual resistance factor (RRF) (RF from 1.82 to 6.88, and RRF from 1.29 to 7.97). The decline curve analysis was used to obtain net incremental oil by gel injection treatment. Results from two well patterns conducted gel pilot test in 2009 indicated that water cut reduction ranged from 3.2 to 36.8% and average oil production increases 15.7m3/d. Based on results, another two wells in 2010 and two wells in 2011 were conducted, and we received good effectiveness by gel treatments.

The pilot test & evaluation technology provide the foundation for promoting application of techniques to stabilize oil rate and control water production in conventional heavy oil reservoirs of China offshore oilfield
The Effect of Bottom Water Coning and Its Monitoring for Optimization in SAGD
Authors: Shahbaz Masih , Kevin Ma , Sanchez Julio , Patino Fabian , Boida Lindsey
Published: June 2012

The performance of steam assisted gravity drainage (SAGD) depends, mainly, upon reservoir characteristics e.g. porosity, permeability and heterogeneity, well bore hydraulics e.g. steam quality, the length and size of wellbores and operational parameters e.g. reservoir and wellbore subcools. However, in reservoirs with underlying bottom water, the performance of SAGD depends on vertical offset between bottom water and producer and pressure differential between bottom water pressure and bottom hole flowing pressure of the producer. Bottom water can act as a heat sink is a known fact, therefore, it can affect project oil rate, steam rate, steam oil ratio (SOR) and, ultimately, the economics of the project. Bottom water can affect heat transfer within reservoir by the injected steam in case of water coning or steam loss to the bottom water. Produced water chlorides concentration (PPM) is an important indication of bottom water coning because of difference in the chemistry of injected steam and bottom water. The chlorides material balance depends upon water saturation in bitumen zone (connate water), formation water chlorides concentration, produced water chlorides concentration and water cut. This study will shed light on significant impact of bottom water coning on SAGD performance through reservoir simulations. It will, also, describe contribution of each of the aforementioned parameters (water saturation in bitumen zone, formation water chlorides concentration, water cut and produced water chlorides concentration), which is very significant, on chlorides PPM material balance for bottom water coning analysis. And it will, also, describe how the safe limit of produced water chlorides PPM (produced water chlorides PPM at which no bottom water is produced) is affected by each of these parameters.
Study of Solvent Injection Strategy in ES-SAGD Process
Authors: Jiang H. , Deng X. , Huang H. , Beaulieu G. , Heck G. , Akinlade O. G. , Nasr T. N.
Published: June 2012

This paper presents a simulation study on the operational parameters of the ES-SAGD process based on an ES-SAGD lab experiment. A numerical model that incorporated the measured data on key physical properties was validated by detailed history matching of the ES-SAGD lab experiment with n-hexane as the solvent. This numerical model was used to evaluate the performance of ES-SAGD with different operating strategies. The simulation results indicate that oil rate lifting from hexane injection is significant in the early stage of the ES-SAGD process but becomes less effective in the later stage of the process. Improved solvent efficiency can be achieved by adjusting operating parameters such as the start time for steam-solvent co-injection, the duration of the steam-solvent co-injection period and the solvent concentration in the steam-solvent injectant. Results from this study could provide a guideline for the design of a solvent injection strategy for field application of ES-SAGD process.
In Situ Combustion as a Followup Process to CHOPS
Authors: Chen Joyce , Coates Roy , Oldakowski Kaz , Wiwchar Brian
Published: June 2012

There are a large and growing number of Western Canadian heavy oil deposits that have been depleted using primary cold production (CHOPS) methods. At their economic limit these methods leave behind 85 % to 90 % of the OOIP while significantly altering the reservoir conditions from their initial state. The oil remaining is a significant target for a follow up process; however, presently there is no demonstrated EOR process that can economically recover additional oil from these deposits in their current condition.

The application of in situ combustion in a reservoir that has under gone CHOPS has several attractive features. The wormhole network created during primary production provides the injectivity required to initiate and sustain high temperature combustion. The interconnected wormhole channels between adjacent wells supplies a conduit for mobilized oil to flow to production well thus minimizing liquid blockage and ineffective conformance.

To assess the potential of in situ combustion as a post CHOPS process a laboratory study was carried out examining the behavior of in situ combustion under conditions representative of the reservoir at the end of CHOPS. A total of seven physical simulation experiments were carried out in the Heavy Oil and Oil Sands laboratory of the Alberta Research Council (now part of Alberta Innovates – Technology Future). Test conditions of these experiments included high permeability channel vs. no high permeability zone, partially filled high permeability channel vs. completely open channel, dead oil vs. live oil dry combustion vs. wet combustion, and normal air vs. enriched air injection,.

Results of the experiments are encouraging for the application of in situ combustion in CHOPS reservoirs. The high permeability wormhole channels provided injectivity to initiate and sustain combustion and the presence of the channel lead to improved conformance with no gravity overriding of the combustion front. Localized coke plugging of the channel prevented the combustion front from prematurely breaking through to the production well, even with a completely open wormhole channel.
Feasibility Study of Hot Waterflooding Technique to Enhance Heavy Oil Recovery: Investigation of the Effect of Well Spacing, Horizontal Well Configuration and Injection Parameters
Authors: Torabi F. , Qazvini Firouz A. , Crockett M. , Emmons S.
Published: June 2012

Among several oil recovery techniques, hot waterflooding through thermal displacement processes could potentially increase oil recovery by decreasing oil viscosity, thus decreasing the mobility ratio at a relatively low cost compared to other thermal methods such as SAGD or in-situ combustion. These methods can also be applied in specific in-situ conditions such as formation sensitivity to fresh water. This paper examines the performance and feasibility of hot waterflooding and compares the performance with a conventional recovery scheme of a heavy oil reservoir with an oil gravity of 10.6 °API and viscosity of 13,400 mPa‧s (at 22 °C) from the Lloydminster area (Canada); the approach includes numerical thermal simulation and economical analysis of each process. First, the performance of a hot waterflood on a generic model consisting of a 5-spot injection pattern was investigated. Then four field designs were recognized from several previously analyzed patterns. The effect of well spacing, horizontal well configuration, injection parameters, as well as the impact of incremental temperature adjustment of waterflood on heavy oil recovery were studied. More than 220 models were built on the final patterns and the most economic configuration was found to have four horizontal producers and four horizontal injectors with a well spacing of 67 m. This arrangement resulted in a recovery factor of more than 30 % of the oil originally in place (OOIP). The most economic injection rate was determined to be 400 m3/day of water at optimum injection temperature of 80 °C. It was also observed that by increasing the temperature of the injected water, the oil viscosity could be reduced to less than 100 mPa‧s. This improved the oil recovery and production rate, delayed injection breakthrough, and reduced water cut. From the results, the highest injection temperature of 100 °C could be recommended; however, the incremental oil versus the amount of heat and facilities required would not be justifiable from an economic point of view.
Successful Application of Discontinuous SAGD Technique to Maximize Oil Recovery in Alberta's Oil Sands
Authors: Nguyen Huy X. , Bae Wisup , Nguyen Danh H. , Tran Xuan V. , Ta Dung Q.
Published: June 2012

The steam assisted gravity drainage (SAGD) process has proven to be an effective thermal recovery method for heavy oil and bitumen production. Recently, some innovative techniques based on the background SAGD operation have been applied such as conventional SAGD, Fast-SAGD, Hybrid SAGD, FA-SAGD. However, there has been much dispute over the question of economical efficiency due to high capital investment, operating costs, and the fluctuation of oil and gas prices. The integration of economic and technical aspects for SAGD performance plays an important role in field operation. Main problems to solve are how to design optimal operating conditions for a reasonable steam requirement with certain injection pressure to maximize economic feasibility under reservoir conditions.

The previous literatures implemented sensitivity analysis and optimization of SAGD performance by classical methods based on numerical simulations lead to a lack of confidence level and ignored interactions effects between considered parameters, which may cause low efficiency issues in a field operation. In addition, the SAGD economic model in previous studies have not fully information with limited consideration on few factors. These restrictions can be avoided by the application design of experiment and response surface methodology to determine the optimal operating conditions for the production prediction. Then, discontinuous SAGD technique was operated to control the amount of injected steam at several specific injection time intervals.

This study represented that the discontinuous SAGD performance is applied to three major formations of Alberta’s oil sands. The results showed that both oil recovery factor and economic profit are much higher than other techniques, especially the effective at deeper burial reservoirs of Clearwater and Bluesky formations. Moreover, amount of injected steam and water cut reduced significantly to cause lower operating costs as steam cost, led to increase NPV as well as minimal environmental damages.
Low Cost Production Gains from CHOPS Wells with Extremely Viscous Oils
Authors: Minish Travis , Yule David
Published: June 2012

Production of heavy oil from Alberta’s vast reserves continues to be a costly and capital intensive endeavor. To date considerable research has been focused on mining, SAGD, in-situ combustion, and vapor extraction. A new chemical dispersant technology has been introduced in the past year that reduces the apparent viscosity of the produced fluids from wells in the heavy oil fields around Lloydminster, Alberta, reducing the power required to drive the downhole progressive cavity pumps (PCPs), allowing pumping rates to increase, and increasing daily oil production by up to 300%. The primary benefit is removing the obstacle of pump speed limitation due to high oil viscosity.

CHOPS production suffers from many challenges. Principally, the cold heavy oil exhibits high viscosities, in some cases in excess of 100,000 centipoises (cPs). Over the past two decades, technological advances in downhole PCPs, rod strings, well heads, and power units have improved the ability to produce heavy oils. However, when viscosities approach or exceed 100,000 cPs these advances do not overcome the excessive drag created by the heavy oils as they travel up the production tubing. The newly developed chemistry creates a dispersion of oil in water with a much reduced overall viscosity and increased mobility. The result: more oil loading into the pump, less drag along the rod string and production tubing, lower power requirements, the ability to increase the pump RPMs and, therefore, increased oil production.

This technology was developed in Western Canada and has proven itself to be successful at increasing oil production, improving on-time, and reducing servicing on Canadian heavy oil wells produced by way of cold recovery methods. This technique could be utilized in other heavy oil fields throughout the world where production rates are limited by the issues created by extreme oil viscosities.
A Novel Approach for Determining Wormhole Coverage in CHOPS Wells
Authors: Xiao Lei , Zhao Gang
Published: June 2012

In this study, the comparison of the transient pressure responses of different wormhole patterns has been comprehensively studied. The modeling results show that transient pressure and production responses vary significantly due to different wormhole structures and reservoir area that embeds with the structure. A concept of effective wormhole coverage is proposed for the first time in this study and its corresponding wormhole model has been well established and validated to study the effective wormhole coverage for wells in the process of Cold Heavy Oil Production with Sand (CHOPS).

Type curves developed for CHOPS wells with wormholes in this study can be applied to analyze transient pressure and production data from wormholed heavy oil reservoirs. Effective wormhole coverage and branches can be reasonably estimated using type curve matching. This work helps offer important parameters in further optimization of post-CHOPS processes such as post-CHOPS EOR planning and infill well drilling.

Type curves for effective wormhole coverage with different numbers of effective wormhole branches were developed for CHOPS wells in this paper. Once either the transient pressure data or production data are matched with the developed type curves, the number of effective wormhole branches and match points are recorded. The effective wormhole coverage can be subsequently determined using the equations developed in this study. In addition, once the number of wormhole branches and effective wormhole coverage has been determined, sand production data can be utilized to help determine the diameter of effective wormholes. It should be noted that, prior to the use of the type curves, formation properties and foamy oil properties should be prior known information.

In CHOPS, the presence of wormholes is considered to be one of the most important factors which contribute to enhanced production rate. Due to the complexity of wormhole phenomena, few methods have been introduced to determine wormhole coverage quantitatively. The novel approach presented in this paper is aiming at providing quantitative information of wormholes by analyzing transient pressure, production rate, and sand production data simultaneously.
Sand Prediction by Different Criteria and a Validation by a Perforated Test in a Sandstone
Authors: Wang Y. , Papamichos E.
Published: June 2012

Sand production in a perforated sample is determined by the onset of a significant discrepancy between strains in two orthogonal directions. The onset is also analyzed by three different sanding models, i.e., shear failure, cohesive tensile failure, and the effective plastic strain (EPS) models, respectively. Comparing these results, we conclude that the results with the shear failure criterion provide the most conservative prediction, and the EPS can provide the closest results to the testing one, given adequate plastic yielding and sanding parameters. Comparing with the cylindrical cases (open hole), both the plastic radius and critical strains calculated for the perforated cavity (cased hole) cases are calculated. A critical equivalent plastic displacement (EPD) is proposed as only one additional parameter is required on top of those from a typical elastoplastic model and such a criterion allows us to determine the sanding onset directly, those using stress, strength or strain whereas can only be indicated or interpreted indirectly, yet difficult to measure in practices.
Field Results for Recovering Oil from A Steam Project Pressure Isolation Wall
Authors: Miller Karl A. , Xiao Yi
Published: June 2012

The Lloydminster Saskatchewan area Pikes Peak steam project has been on production since 1982. A key part of the development strategy was use of an undeveloped pressure isolation wall to allow the two halves of the pool to be developed using different time schedules and exploitation processes.

Use of the pressure isolation wall allowed different exploitation options to be used, but during late project life the oil left in the wall needed to be recovered to enhance project economics. A significant challenge to recovery of the oil in the wall was the lack of pressure containment or oil saturation on both flanks, resulting in the need for a very gentle recovery process to avoid pushing the oil outside the wall.

On the basis of numerical simulation results the recovery process selected for the wall was use of two CSS horizontal wells operated in a gentle manner. After the horizontal wells were drilled, however, temperature logs showed the reservoir surrounding one of the horizontal wells had already been heated by offsetting steam injection, and that well has been continually produced at good rates without the need for steam stimulation. The second new horizontal wall well has been successfully operated using the CSS process designed using numerical simulation.

The results of this field study show that the oil in a wall used to pressure isolate sections of a steam project pool can be economically recovered without pushing the oil into the adjacent depleted areas by use of processes designed to account for local wall conditions.
Multilateral and Geosteering Technologies as a Solution for Optimum Drainage of Heavy Oil of Thin and Heterolithic Sands in Junín Block of the Orinoco Oil Belt
Authors: Palermo Jose , Ramos Joel , Jurado Maryuly , Brazon Carmen , Rondon Leonque , Alfonzo Pedro , Bonalde Antonio , Garcia Wendy
Published: June 2012

Petrocedeño is one of the companies that operate in Junín Block of the Orinoco Oil Belt. This block is located on the southern flank of the eastern basin of Venezuela and produces 150 thousand barrels per day from about 700 wells. Exploitation of this field began early in 2000 year, draining the sands with greatest potential (rock quality in terms of thickness and homogeneity). Today, the amount of this type of sand is reduced; however huge reserves still are in this complex reservoir. About 20 wells have been drilled in Unit C2, deltaic depositional environment with average sand thickness ranging from 10 to 20 ft. and heterolitic beds. Due to these characteristics of the sands, production results of these wells are far away from estimations.

Multilateral technology has been used to increase the amount of reservoir exposure in these heavy-oil fields with great success. Sandy problems, observed in most of the 15 multilateral wells drilled in the area, have been solved by cementing the system junction. On the other hand, application of a real-time geosteering technique has allowed a flawless wellbore placement within a reservoir with a challenging stratigraphy and complex sedimentological environment in Junín Block of Orinoco Oil Belt.

Petrocedeño used Multilateral System level 4 together with Azimuthal Deep Resistivity technologies to face this challenge. Multilateral advanced drainage architecture to increase reservoir exposure from a single surface location, minimizing collision risk, and to improve production. And Logging-while-drilling with Azimuthal Deep Resistivity tool in conjunction with specialized modeling and wellbore positioning techniques was used to enable swift reaction to maintain the well path within the reservoir boundaries in these thin laminated sands.

First Multilateral level 4 well was drilled and geosteered in deltaic C2 Unit on November 2011. Geoscientists and drilling engineers worked as a multi-disciplinary team to make the best wellbore trajectory decisions to position YC36 hole into the best zone of the reservoir along of 5,265 feet. This publication will describe application of multilateral and geosteering technologies in YC36 well. Economical analysis will be presented and explained, as well as production results.
Thoughts on Simulating the Vapex Process
Authors: Cuthiell David , Edmunds Neil
Published: June 2012

The Vapor Extraction (Vapex) process and its many hybrid variants have attracted a great deal of attention as potentially less energy intensive alternatives for exploiting heavy oil and bitumen resources. However, despite much work over the past two decades, uncertainty remains about the basic mechanisms, the scaling aspects and the most appropriate methods of numerically simulating these processes. This paper offers some insights into several of these outstanding questions. The questions are examined in the context of an extensive and well-documented set of Vapex experiments carried out by Maini and his colleagues over the past 10 years.

We have experimented with different methods of simulating these experiments using a physics-based reservoir simulator. Despite the high permeability (greater than 200 Darcys in all of the experiments), we find that capillary pressure plays a significant role in the drainage. The simulations suggest that most of the drainage takes place in the capillary transition zone along the edge of the vapor chamber, rather than in the single-phase zone ahead of it which has not yet been contacted by vapor.

It has been emphasized in the literature that the near-linear scaling of oil rate with height observed in the experiments is dramatically different from the square root of height dependence predicted by the original analytic model of Vapex. However, the experiments also show an increasing solvent fraction in the produced oil phase as height increases. When this "solvent mixing" effect is separated out of the rates, the remaining height dependence is less than linear, though still greater than square root of height.

The relative roles of molecular diffusion and mechanical dispersion in Vapex have been widely discussed in the literature. Generally, mechanical dispersion is expected to play a larger role in these high permeability experiments (vis-à-vis the field), due to larger fluid velocities. We present a method of inferring the diffusion/dispersion present in the simulations, despite a hidden component of numerical dispersion caused by the numerical method itself. We find that the experiments are well matched with values of diffusion and dispersion in line with literature correlations, and that the contribution of mechanical dispersion is perhaps not as large relative to that of molecular diffusion as might be expected.

The paper also provides some thoughts on questions we believe are still unanswered, including mechanisms behind the height dependent mixing phenomenon and the scaling of the experimental results to the much greater heights and lower permeabilities characteristic of the field.
PVT Correlations for Trinidad Oil Offshore the Southwest Coast
Authors: Singh T. , Hosein R.
Published: June 2012

Reservoir fluid properties such as bubble point pressure, oil formation volume factor and solution gas-oil ratio are used for the evaluation of reservoir performance and reserves estimation. Laboratory analyses of these properties are not always available and they are best estimated from correlations. The available correlations were developed for both worldwide applications or for specific regions since oil from different regions vary in compositions. In this study correlations by Standing, Vasquez and Beggs, Glaso, Al-Marhoun, Petrosky and Farshad and Velarde et al were tested to estimate the above mentioned PVT data for Trinidad oils offshore the Southwest Coast. A spread sheet was developed for the calculations and the data for the evaluations were taken from twelve PVT reports.

The results show that the Velarde et al correlations gave the best estimate of the aforementioned PVT data for the twelve available PVT data sets. A comparison of the estimated and experimental PVT data show differences of less than ± 7.0 % for bubble bubble point pressures, less than ± 4.0 percent for oil formation volume factors and less than ± 10.0 percent for solution gas oil ratios. These results indicate that the Velarde et al correlations can be used to obtain accurate estimation of the above PVT properties for Trinidad oils offshore the Southwest Coast for future reservoir engineering calculations.
Study of the Success Factors in Continuous Steam Injection: Field Case, Colombian Middle Magdalena Basin
Authors: Trigos E. M. , Rueda S. F. , Rodriguez E. , Espinosa J. S.
Published: June 2012

In Colombia, there are several heavy oil fields where cyclic steam stimulation have been successfully applied for over 25 years and although it is assumed that the reservoir temperature is high and the conditions are ideal for making the leap to continuous steam injection, some studies apparently show that this technique is not feasible for the reservoir; in fact, between 1992 and 1994, the implementation of a pilot did not reach the expected results.

From this fact raises the question: What are the key factors that ensure the success of a continuous steam injection pilot? To solve this question, a numerical simulation and analytical model based study was performed, showing that the performance of the technique lies in minimizing the energy losses and supplying only the necessary heat according to each stage of the process, these practices are known as heat management.

It was found that critical aspects of heat management are: reducing well spacing, selection of open thickness to injection, perforated intervals, completion design, injector well distance from generator and injection surface line conditions, as well as constant reservoir temperature monitoring, from which the energy requirements at each stage of the process is determined and avoid an excessive injection rate which goes against project economics.

For the field case it was found that: the well spacing should be reduced from 10 to 2.5 acres, the need of using selective sequential injection scheme (due the interbedded shale), the injection rate should be reduced to 46% a year after starting the process and also change the type of insulation on the surface lines. In this paper, the methodology and tools used for factor evaluation and process optimization are presented.
Big Bore Expandable Liner Hangers for Offshore and Deepwater Applications Reduces Cost and Increases Reliability: Global Case History
Authors: McCormick J. , Matice M. , Cramp S.
Published: June 2012

Reducing rig time and material costs for offshore wells is critical to a project’s financial profitability. With the dramatic increase in the number of deepwater wells, new technologies and methods are needed to quickly and reliably complete wells. A case history of 14 large-bore expandable liner hangers (ELHs) in the Caspian Sea and one in deepwater Gulf of Mexico (GOM) show consistent material cost savings, reduced installation time, improved reliability, and increased versatility over the conventional liner hanger system.

The technological advances of ELH systems have increased well life and improved safety during liner installations over traditional systems. Sealing capabilities with expandable systems have evolved beyond conventional tools and the smooth radial flowpaths allow for greater ease of installation. A series of redundant sealing elements provide a gas tight liner top seal which stops any possible gas migration. Also, with the ELH system, rotation and reciprocation while cementing are possible.

This paper will describe offshore wells and the common problems associated with them. Expandable liner hanger technology will be explored to increase operator awareness of an additional technology. An in-depth exploration of ELH technology and the comparison of conventional and ELH systems in the same field are described within this paper.
Optimization of Emulsion Breaker Concentration
Authors: Dubay B. A.
Published: June 2012

Emulsion breaker chemistries are important to the efficiency of crude dehydration and the enhancement of primary produced water treatment. Often a number of specifically developed chemistries are used within a single operation: normal emulsion breakers (primary and secondary/slop oil) and reverse emulsion breakers (coagulants and flocculants). These chemistries must be compatible with each other and used at optimum concentrations.

Determining optimum concentrations require three stages: research and developmental chemistry, ‘Bench Top’ bottle-testing of crude and field testing. Of the three stages field testing is the most critical as based on the number of fluid streams, components and varying process conditions often laboratory testing and process modeling alone cannot effectively simulate what happens in reality.

This paper identifies a particular, successful case study where ‘Bench Top’ bottle-testing of produced water samples from a particular crude dehydration plant followed by optimization in the field enabled the plant to meet its required produced water effluent discharge level for total petroleum hydrocarbons (TPH). The ‘Bench Top’ bottle-testing helped to recommend the right type and concentration of reverse emulsion breakers for the particular crude dehydration plant. These products were then applied in the field at the recommended concentrations and optimized until the required produced water effluent discharge level for total petroleum hydrocarbons (TPH) was achieved. The approach, test methods and results are documented.