bluuebunny/crossref_metadata_2025 huggingface dataset:
Testing Results of an Economical Mesh Screen for Thermal Applications
Authors: Smith Kevin , Bowen Eddie
Published: June 2014

Slotted liners have predominantly been selected to provide a low cost control of sand/solids production in heavy oil applications where the need for steam injection is required to reduce the oil's viscosity in place making it mobile. The biggest challenge with slotted liners is the inflow area. Typically, this can range from 2-3% depending on the width, length, and number of slots per foot. This leads to plugging tendency over time.

The advent of wire wrap screen jackets was an improvement to slotted liner technology. Using a longitudinal wire rib and a shaped wrap wire, a series of openings representing a specific gauge can be manufactured into a wire jacket. This wire jacket is then slipped onto a perforated base pipe, creating a screen product. Although wire jackets improved the area to flow, it was still limited to inflow areas of 6-12% depending on the slot opening. Albeit an improvement to plugging resistance, it still provides a less than desirable flow area to accommodate plugging over time without restricting flow. Typically, the least amount of flow area can be found in the perforated base pipe.

Both slotted liners and wire jacket screens have vast experiences in thermal applications but very limited experiences using a mesh filter type media in these applications. As premium mesh filtering screens have become recognized and accepted during the past few decades there has not been much in the form of thermal testing to qualify these products for cycling temperature environments. The design of a premium mesh can deliver inflow areas in the range of 30-55% depending on the nature of the design, woven v. stacked layers bonded or sintered in place. This improvement in inflow area increases the time to plug exponentially.

The intent here is to show the results of thermal testing conducted with an economical mesh screen, supporting its use in the high temperature cycling that occurs during cyclic steam and SAGD applications. Using a myriad of designs, with and without welds, tests of multiple thermal cycles ranging from ambient to 950°F were conducted in the following modes: 1) free floating, 2) both ends fixed, 3) a single end fixed, and 4) gravel packed in place. Based off these results an optimal design prevailed.
Bitumen Extraction by Expanding Solvent-Steam Assisted Gravity Drainage (ES-SAGD) with Asphaltene Solvents and Non-Solvents
Authors: Mukhametshina A.. , Hascakir B..
Published: June 2014

Steam Assisted Gravity Drainage (SAGD) is a proven enhanced oil recovery technique for oil sand extraction. However, the environmental and economic challenges associated with steam generation limit the application of this technology. To address these issues, we investigated the effectiveness of Expanding Solvent SAGD (ES-SAGD) over base SAGD on a bitumen sample (8.8 °API). Experimental studies are conducted with a two-dimensional physical model. Different strategies for solvent injection are tested (co-injection and cyclic injection) to examine the deposition of polar fractions of the bitumen on porous media or producing polar fractions with non-polar ones. To investigate the level of oil upgrading while toluene is used as asphaltene soluble solvent, n-hexane was selected as asphaltene insoluble. Steam chamber development is monitored with temperature profiles from 47 separate positions. Steam oil ratios, solvent oil ratios, and the level of oil upgrading in terms of viscosity reduction and API gravity improvement are evaluated together. Environmental footprints of SAGD with ES-SAGD are discussed in terms of solvent toxicity, total produced greenhouse gases, and asphaltene precipitation with FTIR analysis on postmortem samples. Furthermore, the energy intensity of the processes is assessed by considering steam generation and solvent costs. This study reveals that co-injection of hydrocarbon solvents with steam enhances the steam chamber development with higher oil production rate. Moreover, ES-SAGD results in recovery of more upgraded oil and has less environment impact. We observe that the selection of the solvent type and injection strategy are the most crucial parameters for the design of hybrid SAGD process and solvent cost can be minimized by using the recycled solvent for continuous injection of solvents. High energy consumption for steam generation during SAGD process can be reduced by co-injection with steam proper solvent type at proper injection strategy. This experimental study reveals that ES-SAGD process has environmental and economic benefits over base SAGD. However, some solvents can cause undesirable effects due to the asphaltene destabilization and precipitation in production or transportation lines. Results of this work can be used to better address solvent interaction with polar components during SAGD.
Identification of Winsor Type III Micro-emulsion for Chemical EOR of Heavy Oil
Authors: Sim Steve S. , Wassmuth Fred R. , Bai Jiang
Published: June 2014

Application of phase behavior studies to optimize chemical formulation for heavy oil EOR is not very common due to difficulties in identifying micro-emulsion in the presence of highly viscous and opaque crude oil. Currently, selection of ASP system for heavy oil EOR is mostly based on IFT value when other selection criteria such as surfactant adsorption, and chemical compatibility, are met. This omission of phase behavior study in the evaluation process can often lead to poor choice of chemical system since the quality of the micro-emulsion generated by the system is unknown and may not exhibit the critical properties (viscosity, stability) required to mobilize capillary trapped heavy oil.

This paper presents laboratory procedures for the optimization of ASP system for EOR of a viscous (>10,000 mPa.s) and high TAN (> 2 mg KOH/g) heavy oil using both phase behavior studies and IFT measurements. The resulting optimized ASP system, when mixed with the candidate heavy oil, displays Winsor type phase behaviors comparable to light oil/ASP system. These Winsor type III heavy oil micro-emulsions are stable and have much lower viscosity (150 - 350 mPa.s) than their parent crude oil. During the phase behavior study, it was observed that the natural petroleum soap from the crude oil plays an important role in the formation of the micro-emulsion and lowering of IFT. Effective utilization of petroleum soap presents in the crude oil during chemical EOR will dramatically reduce chemical cost and improve surfactant propagation within the reservoir. Recovery of the viscous heavy oil from Berea core with this optimized ASP system was excellent (~80%). The ability of this ASP solution to recover capillary trapped oil was demonstrated from the amount of incremental oil produced from a Berea core sample which had been extensively flooded with polymers. To our knowledge, identification of well characterized and thermodynamically stable Winsor type III micro-emulsion from heavy oil/ASP system has not been reported previously. Results from this study can lead to development of improved procedure for optimization of chemical system for heavy oil recovery.
Selection of Optimal Solvent Type for High Temperature Solvent Applications in Heavy-Oil and Bitumen Recovery
Authors: Marciales A.. , Babadagli T..
Published: June 2014

The selection of most suitable solvent for an efficient heavy-oil recovery process is a critical task. Low carbon number solvents yield faster diffusion but the mixing quality may not be high. Also, high carbon number solvents yield a better qulity mixing (much less asphaltene precipitation) but the mixing process is rather slow. Hence, the understanding of solvent selection criteria for solvent-aided recovery processes has established two main aspects of oil-solvent interaction: (1) Oil-solvent mixture quality and (2) rate of mixture formation.

Oil-solvent mixture quality is determined by two parameters: (1) Viscosity and (2) asphaltene precipitation. The rate of mixture formation is quantified by the diffusion rate. These two parameters need to be quantitatively and qualitatively determined to select the suitable solvent for heavy-oil recovery also supported by static experiments that measure solvent diffusion (and oil recovery) from a rock saturated with heavy-oil and exposed to solvent diffusion at static conditions.

This paper focuses on these tests and uses three oil samples with a wide range of viscosities (250-153, 000 cp), and three liquid solvents with different carbon numbers varying between C7 and C13. The methodologies applied for diffusion rate measurement were optical applying image analysis under UV light (for processed -mineral- oil) and CT scanning (for heavy-oil obtained from fields). Next, viscosity and asphaltene precipitation measurements were conducted after mixing the crude oil and solvents to quantify the mixing quality.

Then, core experiments were performed on Berea sandstone samples using the same solvent-heavy oil pairs to obtain the optimum carbon size (solvent type)-heavy oil combination that yields the highest recovery factor and the least asphaltene precipitation. Based on the fluid-fluid (solvent-heavy oil) interaction experiments and heavy-oil saturated rock-solvent interaction tests, the optimal solvent type was determined considering the fastest diffusion and best mixing quality for different oil-solvent combinations.
The research and application of Hydraulic Jet Drilling Technology In CSS
Authors: An Jiuquan
Published: June 2014

Liaohe Oilfield is the largest heavy-oil production base in china, and Circulate Steam Stimulation (CSS) is one of most important thermal development modes in heavy oil production. Utilizing the advantages of Hydraulic Jetting Drilling Technology, such as the deep penetration, more fractures connection, larger drainage radius and environment-friendly, as well as improve the heating effect in CSS wells, to increase the development performance of the remaining oil. This paper introduce the basic principle of Hydraulic Jet Drilling, and according to the reservoir characteristic of Block Gao-3624 in Liaohe Oilfield, optimize the design parameters, and meanwhile, analyze the feasibility for the application of Hydraulic Jet Drilling in combination with CSS measures, and finally accomplish the first domestic field application in the glutenite reservoir. From the field data, the increase extent of production rate could reach 200%, showing a great promising future for this technology.
Equilibrium or Nonequilibrium Models: A Critical Issue in Determination of Gas Diffusivity in Oil
Authors: Saboorian-Jooybari H. , Dejam M. , Chen Z.
Published: June 2014

Accurate simulation, design and implementation of any gas injection and solvent-based oil recovery processes requires a thorough understanding of a gas diffusion coefficient. This parameter is usually determined by monitoring gas pressure in a PVT cell during a pressure-decline test and analyzing the data by developing mathematical models that are different in imposed boundary conditions at a gas-liquid interface (the so-called equilibrium or nonequilibrium boundary conditions). Classically, the equilibrium boundary condition was applied at the gas-oil interface with the assumption of saturated interface at all times. But, recently in a number of researches it has been claimed that some time is required before establishment of the equilibrium state at the interface. These researchers considered existence of the non-equilibrium state and used a Robin-type boundary condition to account for the effect of resistance at the gas-oil interface on gas diffusion into oil. This paper considers these boundary conditions and investigates the effects of taking into account nonequilibrium nature of a diffusion process on estimation of mass transfer parameters using a lot of literature pressure-decay data of CH4, C2H6, CO2 and N2 dissolution in Athabasca bitumen at two different temperatures (50 and 90 °C) and an initial pressure of 8 MPa. Mass transfer parameters (a diffusion coefficient and a mass-transfer coefficient) are individually determined for each test by means of the equilibrium and non-equilibrium models and compared with each other. It is concluded that the values of the diffusion coefficient calculated by the equilibrium and non-equilibrium models are in an excellent agreement, indicating sufficiency of the classical mass transfer models to estimate the diffusion coefficient. On the other hand, although the non-equilibrium effects exist during gas dissolution in oil, applying a Robin-type boundary condition at the two-phase interface is not significant enough to affect the gas diffusion process.
A New Semi-analytical Model for Predicting Steam Pressure and Temperature in Annuli
Authors: Gu Hao , Cheng Linsong , Huang Shijun , Zhang Huideng , Lin Menglu , Hu Changhao
Published: June 2014

An excellent design of steam injection projects requires accurate prediction of bottomhole steam pressure, temperature and quality. However, it is not always easy to meet the requirement when we design concentric dual-tubing steam injection schemes due to the complexity of downward steam/water flow in annuli. Also, previous methods for estimating pressure gradient in annuli, such as mechanistic models and empirical correlations, are either time-consuming or inaccurate.

In this study, we present a new semi-analytical model to predict steam pressure and temperature in annuli. It is based on Coulter-Bardon equation and on mass and energy balances in the wellbore. A more rigorous thermodynamic behavior of steam/water mixture is taken into account. More importantly, one-to-one correspondence between pressure gradient and temperature gradient of saturated steam is reasonably developed and applied in our further derivation and simplification. It is because of the simplification that we do not have to use mechanistic models or empirical correlations to separately calculate the pressure drop in annuli, which is significantly different from previous work, including Sagar et al. (1991), Alves et al. (1992) and Hasan et al. (1994) models. Our solution procedure is straightforward, the equations of steam pressure, temperature, quality, steady-state heat transfer in the wellbore and transient heat transfer in the formation just need to be coupled and solved iteratively for each segment.

Our model is validated by comparison with measured field data from Liaohe Oilfield, Petro China. The results indicate that the direction of heat transfer between inner and outer tubing depends on wellhead conditions and temperature drop in each tubing. We also show that the equivalent hydraulic diameter is not always a suitable characteristic dimension for steam/water flow in annuli. Moreover, the paper shows that our method can also be applied to single-tubing steam injection design. The predicted results from our modified model are also compared with those from CMG simulator and previous work in our study.
Novel Steam-Resilient Cement System for Long-Term Steam Injection Well Integrity: Case Study of a Steamflooded Field in Indonesia
Authors: Salehpour A. G. , Pershikova E.. , Chougnet-Sirapian A.. , Taoutaou S.. , Adiningtyas D. A.
Published: June 2014

A major challenge of a steamflooded field in Indonesia, one of the world's largest thermal recovery projects, is the short life of the well from the well integrity aspect. The outcome of a joint study group between the operator and the cementing service provider reveals that 77% of the injector wells drilled in a recent period of 5 years required remedial squeeze cementing operations. The operating expenditure of workover operations and the costs of the deferred production to the operator are significant; hence, a cementing solution is needed to improve the efficiency in managing the mature heavy oil reserve.

The current cementing practice calls for placing the API class G cement and silica flour blended system across unconsolidated sand bodies and exposing it to large temperature changes. Results of the stress modeling predict the conventional cement system failure under the anticipated conditions of injection and workover operations. An innovative steam-resilient cement system with tailored thermal and mechanical properties up to a temperature of at least 350° C [650° F], beyond the maximum steam injection temperature of the field, is maintaining the integrity.

Field trials in Indonesia confirm that this new system can be easily integrated into standard cementing operations using conventional equipment. Cement evaluation logs after cement operations prove that proper zonal isolation is achieved. All the candidate wells, first one since January 2011, are currently under the steam injection with no sign of wellbore integrity failure.

This novel cement system, by keeping adequate level of flexibility and optimum thermal properties, provides a long term well integrity solution for any well exposed to similar conditions, such as in fields exposed to steam injection. Operators can rely on cement sheath integrity exposed to thermal processes to produce heavy oils.
An Integrated Approach to Building History-Matched Geomodels to Understand Complex Long Lake Oil Sands Reservoirs, Part 2: Simulation
Authors: Feizabadi Seyed Ali , Zhang Xingquan Kevin , Yang Peter
Published: June 2014

Simulation is one of the most important and powerful reservoir engineering tools for understanding reservoir performance, devising operating strategies, and solving production problems. Simple homogeneous models are suitable for understanding basic reservoir engineering parameters and for simple sensitivity analyses. However in real reservoirs with heterogeneities such as at Nexen Long Lake, a comprehensive geomodel which includes all the available geology and geophysics knowledge is necessary in order to extract the greatest value from the simulation efforts.

A geomodel is representative of the real reservoir if simulation of the geomodel is able to reproduce the production history of the reservoir (history matching). For a typical SAGD pad, the parameters to be matched include the injection and production rates, downhole injection pressures, and pressure and temperature of observation wells.

Based on our experience, for this process to be effective and reasonably timely a team consisting of the geologist, geophysicist, geomodeler, production and reservoir / simulation engineer must work interactively and in an iterative, "trial and error" fashion.

The geomodelling part is presented in Part 1(10), of this paper and in Part 2 the simulation results are reviewed. The simulation process can be divided into three main parts - history matching, sensitivity analysis and forecasting. Once the history matching part is done, the geomodel is ready to be used for the other two parts.

High water saturation zones, also referred to as lean zones and top water, play an important role in different stages of a SAGD project. A detailed strategy is necessary to deal with them and to optimize the production. Simulation results show that one needs to be able to increase the total fluid rate and solve the sub-cool limitations at the time of contact with these lean zones.

The STARS thermal simulator from Computer Modeling Group (CMG) was used to do all the reservoir simulations in this paper.
Modeling of Multiphase Behavior for Water/n-Alkane Mixtures by Use of the Peng-Robinson EOS
Authors: Venkatramani Arun Venkat , Okuno Ryosuke
Published: June 2014

Experimental results in the literature show that the water solubility in the oleic (L) phase can be high at reservoir conditions in thermal oil recovery processes; e.g., 24 mol% in the water/n-eicosane binary system at 41 bars and 523 K. It becomes even more significant as the L phase becomes more aromatic, which is the case with heavy oil and bitumen. Efficient and accurate representation of multiphase behavior, which consists of the L, vapor (V), and aqueous (W) phases, is crucial in reliable numerical simulation of steam injection processes. This research presents multiphase behavior predictions for water/n-alkane mixtures by use of the Peng-Robinson equation of state (PR EOS) with the van der Waals mixing rules.

Binary interaction parameters (BIPs) are first optimized for water with n-alkanes in terms of three-phase curves including upper critical endpoints (UCEPs), where the V phase and the less dense liquid phase merge in the presence of the denser liquid phase. A new correlation is then developed on the basis of the optimized BIP values. Thermodynamic predictions from the PR EOS with the new BIP correlation are given for various mixtures and compared with experimental data available in the literature.

Results show that the PR EOS with the BIP correlation yields reasonable predictions for multiphase behavior of water/n-alkane mixtures. It gives the transition of binary phase behavior between types IIIa and IIIb that is consistent with experimental results. It also can reproduce asymptotic behavior of three-phase curves and the water solubilities in the L phase (xwL) that has been observed as n-alkane becomes heavier. When applied to water-containing reservoir fluids, the PR EOS with the BIP correlation results in a systematic underprediction of xwL. This is expected considering that reservoir oil consists of various types of hydrocarbons and that the affinity towards water is lowest for n-alkanes and highest for aromatics. Accurate xwL predictions can be obtained by systematically reducing the BIP values from the correlation. The correlation developed may serve as the upper limit of BIPs for water with pseudo components that are required for characterizing water-containing reservoir fluids.
Modeling Effect of Permeability Heterogeneities on SAGD Performance Using Improved Upscaling Schemes
Authors: Kumar D.. , Murugesu M.. , Srinivasan S..
Published: June 2014

Fully heterogeneous three-dimensional SAGD simulation models are computationally expensive to evaluate, necessitating the need for simpler models that can capture the overall physics of the process while reducing computation time. This paper sheds some insights into the effect of permeability heterogeneity on SAGD performance, and presents both a physics-based upscaling technique that considers the unique geometry of the steam-plume during the SAGD process, as well as a statistical upscaling scheme based on variable selection and multivariate non-linear regression.

Full physics, two-dimensional SAGD simulations were performed using several stochastic shale models representing different proportions. Subsequently, the vertical variability in the models was averaged using a flow-based upscaling technique to obtain an effective anisotropic ratio. The performance of the upscaled models was assessed using full physics numerical simulation. It was observed that the upscaled anisotropic models gave different results compared to the fully heterogeneous models. The discrepancy between the heterogeneous and anisotropic models is largely due to upscaling. Two approaches were formulated to address this. The first approach iteratively adjusts the anisotropic permeability of the 2D model until a match to the 3D heterogeneous model was achieved. Then a non-linear regression model between the heterogeneous model parameters and the history-matched anisotropic permeability was formulated. In the second approach, an upscaling method considering the flux due to convergent flow towards a line sink was developed.

A key result presented in this paper is that heterogeneity plays a significant role in SAGD performance. Factors such as shale correlation length and proportion affect both the initial steam rise and the lateral spread of the chamber. Traditional upscaling techniques assuming power averages or flow-based assuming uniform flow over a plane are inadequate for approximating heterogeneous models. Statistical schemes such as the one presented in this paper perform much better in capturing the recovery characteristics of the SAGD process in heterogeneous media. Considerations such as optimum well pair spacing and optimal steam-oil ratio for maximizing bitumen recovery require quick evaluation of multiple scenarios and that may be possible using the approach presented in the paper.
Interfacial Rheology of Heavy Oil-Aqueous Systems at Elevated Temperatures and Pressures: Effect of Diluents
Authors: Phan Jenny , Balsamo Vittoria , Nguyen Duy , Maharajh Edward , Champion Nalco
Published: June 2014

In SAGD (Steam Assisted Gravity Drainage) operations the produced fluids are complex water-in-oil-in-water (W/O/W) emulsions. A diluent is often added to reduce the density and viscosity of the heavy crude oil. However, the quality and composition of the diluents may in some cases increase emulsion stability and cause the dehydration of the oil to be more difficult as there are more surface-active agents added to the oil coming from the diluent streams. To simulate temperature and pressure conditions during SAGD operations, this work studied the effect of three diluents on interfacial rheology of a Canadian heavy oil and synthetic brine at 120°C and 130 psi and then correlated with emulsion stability and oil dehydration. When compared to 25°C, all three diluents exhibited higher higher compressibility at 120°C, while the initial interfacial tension, "phase change" area ratio (area ratio at which the phase change from high compressibility region to low compressibility region), and crumpling ratio (ratio of the compressed surface area to the original area at which the interface starts to collapse) exhibited a more complex behavior. The higher interfacial tension and higher compressibility were correlated with the lower emulsion stability at increasing pressure and temperature in the absence of treating chemicals. Increasing ageing of the film from 10 minutes to 1 hour at 120°C had a similar effect on the three diluents, suggesting the formation of a more elastic film as asphaltenes start to cross-link on the interface. The effect of demulsifiers (emulsion breakers-EB and reverse emulsion breakers-REB) on interfacial was also investigated at RT and 90°C. Demulsifiers that produced the minimum interfacial tension (IFT) with changing concentrations demonstrated to be the best demulsifiers in the bottle tests. A synergistic effect in reducing IFT was found when EB and REB when combined.
Application of Intelligent Well Technology to a SAGD Producer: Firebag Field Trial
Authors: Stahl Richard M. , Smith Jennifer D. , Hobbs Scott , Clarke Colin M.
Published: June 2014

Even temperature conformance along the length of the horizontal well is key to maximizing Steam Assisted Gravity Drainage (SAGD) production rates. When temperature logs are run in SAGD producers, temperature variations of greater than 50°C between the hottest and coldest spots are commonly observed. We theorize that this temperature distribution is related to an inflow distribution, and that production rates could be improved if this temperature variance was narrowed.

It is difficult to influence conformance with traditional SAGD producer well design. Flow areas are large, and liquid velocities are low, resulting in small frictional pressure losses. It is not possible to impose a materially different drawdown on hot and cold spots along the horizontal with typical well completion methods.

A field trial is ongoing at the Firebag project in which a production well is equipped with intelligent completion technology. The test well's horizontal liner section is split into four hydraulically isolated zones, with each zone having the ability to provide flow or isolation from the reservoir. The well completion is equipped with optical pressure and temperature (P/T) gauges and distributed temperature sensing (DTS) technology which monitors each segment's performance during operations. The capability to independently and immediately manipulate each segment's production inflow will provide the operator the ability to evaluate the influence of an intelligent completion design on a well's conformance and ultimate oil recovery.
The Measurement of Connate Water Chlorides Concentration and Its Effect on Bottom Water Coning Analysis in SAGD for Optimization
Authors: Masih Shahbaz , Bennett Barry , Savage Mark
Published: June 2014

Bottom water coning has a detrimental impact on the performance of steam assisted gravity drainage (SAGD) causing reduced oil mobility around the producer. It, also, leads to higher steam to oil ratio (SOR). Produced water chlorides concentration can be used as an indication and quantification tool for bottom water coning analysis. The chlorides material balance for bottom water coning analysis depends upon connate water saturation and the concentrations of chlorides in connate water, bottom water and produced water along with the water cut of produced emulsion. Most oil sands are water wet but wettability changes with high steam temperatures and almost all the connate water is drained because of steaming. The safe produced water chlorides concentration, at which no bottom water is produced, depends mainly upon connate water saturation and its chlorides concentration besides water cut and oil saturation. Therefore, careful sampling and laboratory procedures for connate water chlorides measurement is vital in bottom water coning analysis.

The mechanical extraction device (referred to as the plunger) was developed mainly to facilitate the recovery of heavy oil and bitumen samples from oil sands cores. In this study, the plunger technology is employed in order to recover water samples to enable measure connate water chlorides PPM (concentration in parts per million). The measured connate water chlorides are also corrected for drilling fluid invasion. A new material balance for bottom water coning analysis is established based on different connate water and bottom water chlorides concentrations and drainage patterns of connate water and oil saturations. The new material balance is used to determine the safe chlorides concentration and applied to bottom water coning analysis in the field application at Leismer SAGD project.

Since, the earlier study assumed the same chlorides concentrations of bottom water and connate water, the new measurement technique of chlorides concentration of connate water has led to a better material balance calculation for bottom water coning and data analysis. The new material balance has led to a lower safe chlorides limit. It has, also, helped better optimization of steam chamber pressure and steam injection strategy to avoid negative impacts of bottom water conning to enhance oil production and lower SOR at Leismer.
Impact of Fractures Characterization, Wettability and Hysteresis on Thermal Recovery Processes in Carbonate Naturally Fractured Reservoirs
Authors: Ghedan Shawket G. , Kumar Anjani
Published: June 2014

Combination of complex sedimentation environment and carbonates' diagenetic alterations render carbonate reservoirs to be very heterogeneous and often naturally fractured. Heavy oil trapped in carbonate reservoirs worldwide is estimated to be over 255 billion cubic meters. The drastic differences in flow and storage capacity of the fracture and matrix networks trigger the need for larger volumes of steam to be injected to produce one cubic meter of heavy oil production, making the application of thermal recovery processes in these reservoirs to be more economically challenging and highly energy intensive.

Recovery of heavy oil from naturally fractured reservoirs is weakly controlled by viscous forces and mostly controlled by capillary and gravity forces, in addition to convection and conduction heat transfer. This makes proper representation of fracture and matrix characteristics to be of paramount importance to the reliability of modeling thermal recovery processes.

This paper discusses the effect of variable fracture characteristics including fracture typing, spacing, and apertures on the performance of dual permeability models under different thermal recovery processes. Further, the paper demonstrates the necessity to characterize partially mineralized fractures and shows its effect on thermal conductivity from fractures to matrix blocks.

The effect of wettability on the recovery process is also discussed. Oil recovery in fractured reservoirs is highly influenced by imbibition process which is most effective under strong water wetness. The paper addresses the performance under water, oil and mixed wettability conditions. Furthermore, the paper shows that proper representation of capillary pressure hysteresis could cause considerable change in oil recovery performance. The modeling work in this paper helps to curtail any extra optimism that may originate from wrongly characterized dual permeability models. Finally, and in case reservoir characteristics are not well determined then forecasting based on uncertainties of reservoir characteristics should give operators a way to estimate the risk involved in the exploitation process of the carbonate resources.
Pentane as a Potential Candidate for ES-SAGD and Hybrid Processes: Its Phase Behaviour with Bitumen
Authors: Nourozieh Hossein , Kariznovi Mohammad , Abedi Jalal
Published: June 2014

Steam-assisted gravity drainage (SAGD) is a promising method for producing oil sand in Alberta; however, it has been suffering from high energy and water consumption and significant greenhouse gas (GHG) emissions. Solvent-based processes represent an alternative to steam-based processes but they have their own drawbacks. The main problem with solvent-based processes is a relatively low production rate because they rely on diffusion and dispersion mechanisms, which are very slow processes. To overcome the limitations of steam and solvent processes, hybrid processes have been proposed in which steam and solvent are co-injected. As a result, several recovery techniques, such as expanding-solvent SAGD (ES-SAGD) and steam-alternating solvent (SAS), were proposed and patented. However, there is a fundamental lack of basic data and mechanistic knowledge relevant to solvent/heat-assisted-recovery processes. Even the most fundamental experimental data, such as the solubility of commonly used solvents in bitumen, is not available. The quantitative effects of solvent on bitumen viscosity and density, and phase behaviour are also not well understood.

Pentane as a potential additive to steam-based processes has saturation pressure close to steam at in situ thermal process; thus, pentane and its mixtures with other hydrocarbons can be considered for bitumen and heavy oil recovery. In this study, the phase behavior of pentane / Athabasca bitumen mixtures was experimentally studied. The measurements include the properties of phases such as solvent solubility, number of phases, and composition, density, and viscosity of each phase as well as the possibility of asphaltene precipitation. The experiments were conducted over wide range of temperatures (23–200°C) and at pressures (1–10 MPa) which cover single liquid, liquid-liquid and vapor-liquid equilibrium conditions.

The results showed that the solubility of pentane in bitumen was relatively high even at high temperatures leading to significant density and viscosity reductions. The asphaltene was separated as a second liquid phase rather than a solid phase, and there was a transition zone between single liquid and liquid-liquid regions in which the asphaltene was instable in the system. A significant reduction in density and viscosity of bitumen was observed with the dissolution of pentane over studied temperature condition.
Combining Process Safety Data with Environmental Risk Analysis to Prioritise Capital Expenditure on Environmental Improvement Programmes
Authors: Gibbons S.. , Quinn D.. , Pollok D..
Published: June 2014

There has been an increase in the awareness of environmental consequences of major accidents, particularly as a result of the Buncefield fire (UK Hertfordshire Oil Storage Terminal) and the offshore Deepwater Horizon oil spill, and the connection between failures in process safety systems and environmental damage. Whilst there is an obvious link in principle between incidents and environmental consequence, there has been relatively limited work to prioritise planning and preventative expenditure reflecting environmental, as well as safety, outcomes. This paper presents a process whereby integration of process safety data and environmental fate and transport modelling can be used by oil & gas operators to understand and prioritise actions to reduce and mitigate potential environmental risks and to use an understanding of these as the basis for integrated safety planning and management.

In addition to risk ranking major accident events and their consequences, the approach can also be used to help inform emergency planning and the preparedness of operators. One example application of the approach is the use of modelling techniques to analyse the flow routes of released products from secondary containment, factoring-in the influence of man-made structures and drainage infrastructure as well as the fate and transport of material in the environment. Modelled outputs can help identify where improvements in containment systems may be beneficial in reducing risk and in informing emergency response. This paper provides a case study to illustrate how a risk based approach has been applied to enable an agreement with the regulatory authority on an appropriate scope of upgrades to major accident prevention protection measures for environmental protection.

The approach is tiered, to enable an appropriate degree of assessment commensurate with the level of risk; relatively low frequency events are not considered further, but are documented. Removal of those unlikely events through a process of compartmentalisation of a site provides a transparent method by which events which could generate the greatest impact on the environment may be identified. The key conclusion is that a detailed assessment of environmental risk can identify the most appropriate areas of a facility for environmental improvement, and conversely provide a defensible, risk-based rationale significant saving in capital expenditure on programmes which may ultimately serve little benefit in terms of protecting the environment.

The approach outlined has significance across the oil & gas industry as it enables closer integration of process safety and environmental consequence assessments and provides oil & gas operators with a managed approach to making investment decisions which are likely to have the greatest net safety and environmental benefit.
Application of sustainable remediation principles to upstream oil and gas projects opportunities and challenges
Authors: Thomas A. O.
Published: June 2014

Sustainable remediation has been defined as ‘the practice of demonstrating, in terms of environmental, economic and social indicators, that the benefit of undertaking remediation is greater than its impact and that the optimum remediation solution is selected through the use of a balanced decision-making process’. Sustainable remediation has emerged as a significant area of interest for the management of contaminated land and water for regulators, industry and practitioners in Western Europe, the USA and Asia Pacific. It seems likely that sustainable remediation will develop into a key policy and practice consideration in future years. The application of sustainable remediation principles to the management of upstream oil and gas legacy related impacts have not been explored to date.

This paper attempts to define sustainable remediation in the context of onshore upstream O&G operations, demonstrate how sustainable remediation principles could be applied within the context of existing best practice guidance and explore the opportunities that sustainable remediation may bring as well as the barriers that may exist to its implementation.

The primary conclusion is that where existing regulations are absent or incomplete sustainable remediation can offer an improved framework for the management of contaminated land issues that results in solutions that are protective of human health and the environment, inclusive of the views of local stakeholders and is transparent and robust. Where regulations do exist then sustainability should be considered in the context of what is practically achievable. Sustainable remediation can be a driver for improved engagement with stakeholders that can result in locally acceptable solutions that maximize the benefits to local society as well as acting as a catalyst to drive innovative technical solutions. It is recommended that the application of sustainable remediation to upstream oil and gas sites should be examined more closely with a view to developing sector specific guidance and best management practices that promote the incorporation of sustainability and that the procedures for management of contaminated land associated with upstream operations draw on best practices from other parts of the oil and gas sector and contaminated land management as a whole.
How to Make Injection More Effective and Get Production More Optimum - A Good Case From China
Authors: Ming Liu , Shengyun Zhan , Weige Yan , Shigang Ma , Ruichang Yan
Published: June 2014

BZ25-1S oilfield is a large heavy oil reservoir with narrow and thin fluvial channels in Bohai bay developed by CNOOC and Chevron. Due to large well spacing (350-450m), it is difficult to characterize the connectivity between sand bodies and determine the response of oil production on water injection. The early field oil production and pressure declined at the rate of 4.4% per month and 0.6 MPa per month respectively because of insufficient natural energy. The results of water-oil displacement in cores indicate that there was no non-water production period and the recovery factor would not more than 5% when field water cut reaches 70%.

Focusing on these main problems in the reservoir, comprehensive water injection and production optimization technology was applied based on study of detailed reservoir characteristics: 1) Combining research on geology and field outcrops and analysis of reservoir dynamic performance, we carried out detailed reservoir description of sand bodies and systematically analyzed the response of oil production on water injection for this type of reservoirs; 2) An innovative technology of production optimization has been developed. It takes the nature of offshore production technology into account, constantly adjusts water injection rate and controls water production amount so that water displacement efficiency improved; 3) An advanced surface water injection and production technology such as selective injection supporting the implementation of the production optimization techniques has been also developed.

Field production data showed that 95.6% of the wells displayed positive responses to water injection in which led to stable reservoir pressure, slower production decline, and slightly water cut increase. The filed oil rate has been stabilized for about four years without water breakthrough in large scale and the overall recovery factor is expected to improve more than 5%.
The Impact of Layering on Production Predictions from Observed Production Signatures, Shushufindi Project, Ecuador
Authors: Corbett Chip , Lafournere Jean-Paul , Bolanos Jorge , Bolanos Maria Janeth , Frorup Mik , Marin Gustavo
Published: June 2014

The Shushufindi field (Fig. 1) was discovered in 1972 and is sparsely developed, with only 181 wells covering an area of approximately 400 km2. Recovered whole core from the well SSF-151D presents very thin streaks of quartz material, along with carbon and amber, which form vertical permeability barriers in the cored section, approximately one inch thick. Production profiles for many wells in the field present a very gradual increase in the water cut from an active edgewater drive aquifer and demonstrate a layered system. This implies that the vertical permeability barriers are areally extensive, and that they have a substantial impact on production predictions and development scenarios. The challenge for the subsurface team is to represent these thin barriers in a predictive simulation model.

A standard Kv:Kh ratio is insufficient to mimic the observed production response. A very fine-scale geomodel could be considered but is computationally expensive. Vertical transmissibility multipliers are useful in a simulation model, but experiments demonstrate that the lateral extent of the barriers is discontinuous. Diagnostic plots of the well water/oil ratio (WWOR) versus the cumulative liquid production (WLPT) can identify groups of wells with layered production profiles. This information provides a basis to infer the potential for a layered production response from existing well logs. To introduce such discontinuities, a series of randomly generated vertical baffles have been created which provide an improved simulation response in a relatively coarse simulation model.

Early water breakthrough, and excessive water production in some wells caused premature re-completions into other zones. This type of sub-surface modeling provides support for the introduction of intelligent completions to isolate specific layers as part of the development plan.

This paper presents the techniques implemented by the team, the results to date, and a prognosis for the future of the field.
Unveiling Reservoir Characteristics of a Vintage Field, Shushufindi Project, Ecuador
Authors: Lafournere Jean-Paul , Dutan Jorge , Naranjo Michelle , Bringer Florent , Suter Andreas , Vega Jorge , Bolaños Jorge
Published: June 2014

The Shushufindi field, located in the Oriente basin of Ecuador, has been producing since 1972. In December 2011, the field had approximately 150 wells, with a total production of 45,000 bopd. Field operations were then passed to the Consorcio Shushufindi (CSSFD) led by Schlumberger for a period of 15 years. Since then, 30 new wells and 26 workovers have been completed by Schlumberger Production Management (SPM) in the field, with a production of 60,000 bopd in May 2013.

A methodology with four successive distinct phases was created, aiming for a complete reservoir characterization over 18 months prior to delivering the five-year field development plan (FDP) in October 2013. Each petrophysical phase focused on providing a reliable basis for the first two years of operations, and regular updates to the static and dynamic models.

In conjunction with operations support, a comprehensive data acquisition plan was launched with advanced core analysis and special logs to support the advanced reservoir characterization. The deployment of technologies such as the Dielectric Scanner* multifrequency dielectric dispersion service, the combinable magnetic resonance tool, and the FMI* fullbore formation microimager, among others, was key in revealing the reservoir's true characteristics.

Advanced petrophysics delivered a description of the main reservoir heterogeneities and properties, along with a facies characterization tied to an advanced core analysis including capillary pressure and pore throat size measurements. From this, hydraulic flow units were established in a deterministic characterization over the waterflood pilot well patterns. Additionally, a quantitative evaluation of thin beds and low resistivity pay zones provides the potential for their incorporation in the original oil-in-place computation. These findings have contributed to a revision of the depositional concepts for the field.