bluuebunny/crossref_metadata_2025 huggingface dataset:
Analysis and Correlations of Viscous Fingering in Low-Tension Polymer Flooding in Heavy Oil Reservoirs
Authors: Jamaloei B. Y. , Kharrat R. , Torabi F.
Published: February 2011

Post-primary recovery from some mobile heavy-oil reservoirs in Western Canada cannot be improved using thermal methods due to environmental concerns and technical difficulties. Moreover, miscible gas injection suffers from low initial production rates, premature breakthrough, and possible, formation damage. Low-tension polymer flooding (LTPF) can be an alternative in these reservoirs. However, a major technical challenge in LTPF is that a fingered displacement front may occur. This instability reduces displacement efficiency and may invalidate normal method of simulating LTPF performance based on relative permeability and capillary pressure concepts. Also, it introduces an additional scaling requirement for using results of experimental tests in larger scales. Therefore, it is important to predict the nature of instability, to avoid viscous fingering, or, where it is inevitable, to be capable to include it as an additional factor in modeling displacement.

Previous experiments of viscous fingering in immiscible displacements have been conducted in presence of high single-phase permeabilities and linear displacement schemes. The question is whether previous findings are valid in displacement schemes similar to oil-field patterns (e.g., five-spot) in which one should deal with varying velocity profiles from injector(s) to producer(s). Hence, the effect of dispersion caused by varying velocity profiles has not been tested completely on viscous fingering.

To help understand viscous fingering in LTPF in heavy oil reservoirs and to overcome the aforementioned limitations, we conducted experiments in low-permeability, one-quarter five-spot patterns. Foremost parameters including oil recoveries at different times to breakthrough, ultimate oil recovery, pressure drops, cumulative saturation profiles, mean local saturations, fingers length and width, dynamic level of bypassing, dynamic population of fingers, rate of growth of population of fingers and number frequency of the fingers were measured. We have correlated some of these parameters with displacement time and front position.

Analysis of experimentally-observed fingering patterns of LTPF in this study is the most detailed interpretation performed to date, which provides new insights into the onset of fingering and fingers development. Results would help numerical simulation and stability theory to satisfactorily reproduce qualitative and quantitative features of finger growth.
Three-Phase Equilibrium Study for Heavy Oil-Solvent-Steam System at High Temperatures
Authors: Jia N. , Gao J. , Huang H. , Zuo J. , Memon A. , Zhao H. , Ng H- J.
Published: February 2011

Reservoir simulation and research activities of heavy oil production processes such as SAGD, VAPEX or the steam-solvent combined hybrid process require accurate values of equilibrium constants (K-values) at elevated temperatures. However, such data is rarely available in open literature either because of the temperature limitation of PVT equipment or difficulties in performing high temperature three phase vapor liquid equilibrium experiments.

In this paper, with the assistance of a state-of-the-art fully visual PVT cell specifically developed for heavy viscous oils and capable of performing fluid phase behavior studies at temperatures up to 250°C and effectively mix samples with viscosity up to 1,000 cP at test temperature, a heavy oil-solvent-steam equilibrium case study is presented. The heavy oil was mixed with solvent and water at specified weight ratio, temperature and pressure in the heavy oil PVT cell. After achieving equilibrium, the volumes of vapor, liquid and water phases were measured. The samples from each phase were drawn for compositional analysis using gas chromatography and K-values of the hydrocarbon components were examined. The component compositions from this experiment were utilized for equation of state (EoS) model turning. This case study shows that with proper care, the EoS can be characterized and used to match with experimental data for heavy oil.
Case Studies of a Simple Yet Rigorous Forecasting Procedure for Tight Gas Wells
Authors: Nobakht M. , Morgan M. , Mattar L.
Published: February 2011

The dominant flow regime observed in many hydraulically-fractured tight/shale gas wells is linear flow. This flow regime may continue for several years, and will ultimately become boundary-dominated flow, at much later times.

Nobakht et al. (2010) introduced a simplified method of production forecasting for tight/shale gas wells which exhibit extended periods of linear flow. The method is simple as it relies principally on a plot of inverse gas rate versus square root time, and it is rigorous in that it is based on the theory of linear flow and combines the linear flow transient period with hyperbolic decline during boundary-dominated flow.

In the present work, this simplified method is reviewed and applied to almost 90 wells producing from the Montney formation in N.E. British Columbia, Canada. The vast majority of these wells exhibit linear flow for extended periods of time.

The advantages of the simplified forecasting method are: (1) It is not biased towards any flow regimes, as no superposition time functions are used; (2) Reliable forecasts can be obtained without invoking pseudo-time and its associated complexities; and (3) The only parameter that needs to be specified externally is the drainage area.

The method can be used for forecasting horizontal wells with multiple hydraulic fractures. By assigning different drainage areas to each fracture, a relationship can be developed between expected ultimate recovery (EUR) and original gas in place (OGIP) assigned to each fracture. This translates into recovery factor versus number of fracture stages. The resulting forecasts can be used directly to examine the economics of multi-stage fracturing.
Understanding Hydraulic Fracture Geometry and Interactions in the Horn River Basin through DFN and Numerical Modeling
Authors: Rogers Steve , Elmo Davide , Dunphy Rory , Bearinger Doug
Published: February 2011

In the Horn River Basin, evidence points to one of the key elements of a successful well completion being the effective connection of the hydraulic fracture into the natural fracture system, allowing the well to connect to a significantly enhanced drainage volume. However great uncertainty exists with respect to the nature of the natural fracture system and importantly how the hydraulic fracture interacts with it.

To provide a framework to address these uncertainties, an approach has been developed within a Discrete Fracture Network (DFN) code. The DFN approach provides a platform to construct realistic fracture models of stochastically generated fracture elements constrained and conditioned by well and surface data. Simulation of hydraulic frac development through these DFN models using a rule based approach allows the rapid modelling of the interaction between the hydraulic frac and the natural fracture system with calibration of the model being provided by the generation of a simulated micro-seismic cloud. Comparison of the simulated micro-seismic pattern to field measurements increases confidence in the DFN approach and allows the tuning of key hydraulic properties as part of the calibration process.

An additional challenge at this stage of the plays development however is that many of the developments are relatively data poor and therefore the rigorous simulation of detailed models conditioned to well data is often not possible. To address this, a number of simulations were run on more generic models where key properties such as fracture length, fracture aperture and intensity were varied and their impact on the resultant micro-seismic pattern observed. This more parametric approach allows well observations to be interpreted within a better constrained framework of fracture network knowledge. These DFN based simulations were supplemented by detailed geomechanical models using a hybrid FEM-DEM code that allowed the coupled stress-flow modelling of hydraulic frac interaction and pressure evolution, enabling certain stimulation design factors to be considered as well as testing the basis for the more stochastic modelling.

The benefit of these combined simulations is that a framework is developed to integrate, interpret and test all the fracture related information, allowing more guided development decisions to be made as well as identifying critical data gaps to be addressed.
Simulation Study for Designing an In-Situ Combustion Pilot in the Orinoco Belt of Venezuela: From Laboratory Studies to the Field Scale
Authors: Anaya I. , La Cruz R. E. , Alvarez A. J. , Gutierrez D. , Skoreyko F. A. , Card C.
Published: February 2011

In-situ combustion (ISC) is a promising enhanced oil recovery process for the vast heavy oil accumulation of the Orinoco Belt in Venezuela. Combustion tube tests were performed to assess the feasibility of the process in a reservoir of the area. Given the successful laboratory results, it was decided to proceed with the design of a pilot test. Along with the basic design calculations, a simulation model was built to aid in selecting optimum well locations and operating strategies of the pilot. This would also be used for history matching of the actual operation and further optimization. One of the features of the model is the inclusion of the foamy oil behavior exhibited by the oil. For the modeling of the combustion process, a kinetic model developed in-house by PDVSA Intevep using thermo-gravimetric and scanning calorimetry experiments from an analog field, was employed. The first stage of the study involved the characterization of the oil into the same pseudo-components utilized by the kinetic model. A match of relevant PVT data was done for this purpose. In the second stage, the field scale model was history matched with the new fluid model, which included the foamy oil behavior. The best agreement with field measured data was obtained with a dispersed-gas foamy oil model with velocity dependence of the reaction that converts the low-mobility dispersed gas into high-mobility free gas. The following stage consisted of the history match of the combustion tube test, which was partly achieved with an assisted-history-matching tool. In the last stage, the results obtained from the combustion tube match were applied to the field model. In order to determine the most appropriate locations of production and injection wells, several pilot configurations were studied combining vertical and horizontal wells. A sensitivity analysis was completed using operational parameters such as injection rates and distance between producers and injectors wells. Based on ultimate recovery, the best pattern configuration was selected along with the optimum operational parameters. This paper illustrates the application of a workflow for modeling ISC from laboratory experiments to the field scale.
Towards Seismic Detection and Characterization of Gas Hydrate Accumulations in Permafrost Environment: An Example From the Mallik Gas Hydrate Field, NWT, Canada
Authors: Bellefleur G. , Riedel M. , Huang J. , Milkereit B. , Brent T.
Published: February 2011

Three internationally-partnered research well programs in 1998, 2002, and 2007-08 studied the Mallik gas hydrate accumulation in the Mackenzie Delta, Canada, and have allowed successful extraction of subpermafrost core samples with significant amount of hydrates. Gas hydrate bearing intervals were logged with a comprehensive suite of tools and their producibility was tested in 2002 using thermal stimulation and in 2007/08 using depressurization techniques. Thus, the Mallik gas hydrates are well-characterized and are ideal targets for testing geophysical imaging techniques. Here, we apply acoustic impedance inversion to 3D seismic data acquired over the Mallik area to characterize gas hydrate occurrences and to help define their spatial extent away from well control. The inversion method converts reflections into acoustic impedances from which velocity and hydrate saturation were estimated. The extent and geometry of the two lower hydrate zones were mapped with high confidence and show a distribution controlled by local geology. Correlation between the uppermost hydrate zone and the 3D seismic data could not be established with confidence, because of geological heterogeneity and/or inappropriate seismic imaging. The heterogeneity of the Mallik gas hydrates was parameterized following a method based on multivariate conditional stochastic simulation of well-logging data. Following this method, multi-dimensional heterogeneous models of petrophysical properties (Vp, Vs and density) of hydratebearing sediments were constructed and used to assess effects of heterogeneity on gas hydrate volume estimates. Models including small-scale heterogneities provide volume estimate nearly an order of magnitude lower than earlier estimates which did not include effect of heterogeneity.
The Effect of Low Molecular Weight Multifunctional Additives on Heavy Oil Viscosity
Authors: Oldenburg T. B. , Yarranton H. W. , Larter S. R.
Published: February 2011

Highly viscous heavy oil and bitumen are becoming more important in the world energy mix as conventional resources decline. Any successful in situ recovery process must mobilize the highly viscous bitumen and move it to a production well. Standard methods use heat provided by steam (SAGD) or solvent (VAPEX), with encouraging combinations of steam and solvent (ES-SAGD) but these routes have inefficiencies. Alternative ways of mobilizing bitumen might involve viscosity reduction management of more fundamental controls on bitumen viscosity including managing internal physicochemical interactions between the interacting functional groups on different crude oil molecular components. Here we examine the impact of low molecular weight multiheteroatom species (LMWMH) as molecular Velcro linking high molecular weight moieties together by multiple interactions. Most species tested showed only a viscosity reducing dilution effect whereas THF/aniline as an additive showed an additional viscosity reducing effect particularly at low volume fraction of the additive. Considering that this additive is soluble in water and therefore easily transportable to the subsurface bitumen makes it a promising candidate for enhanced in situ bitumen viscosity reduction and thus improved in situ bitumen mobility.
Reservoir Characterization and Flow Simulation of a Low-Permeability Gas Reservoir: An Integrated Approach for Modeling Tommy Lakes Gas Field
Authors: Deng H. , Alfarhan M. , White L. S. , Oldow J. S. , Aiken C. L. , Aguilera R.
Published: February 2011

The Tommy Lakes field is located in northeastern British Columbia, Canada; and is one of the largest Middle Triassic gas pools within the Western Canada Sedimentary Basin (WCSB). The major gas production formation (Halfway/Doig reservoirs) at Tommy Lakes field corresponds to shoreface sands with permeabilities ranging between 0.1 and 3 md, and porosities of 3 to12%. For the purpose of production optimization and field development, a full field reservoir model was developed with the integration of advanced reservoir characterization, hydraulic fracture modeling, and history matching techniques.

This study presents an integrated workflow for modeling the low permeability Doig gas reservoir. A stochastic geostatistical reservoir model was developed based on concepts emanating from an outcrop analog analyzed with terrestrial LiDAR technology and 60 wells that represent the fundamental rock characteristics, structure, facies proportions and petrophysical properties of the Doig Anomalously Thick Sandstone Bodies (ATSB). Structural tops were interpreted from well logs and permeability/porosity relationships established from quantitative log analysis and core-log calibration. Facies were identified in cored intervals and were further grouped into 4 lithofacies. An artificial neural network was used for training the logs of key wells (GR, NPHI, RHOB) and populating the facies distribution of uncored wells. Facies-based log-derived porosity, permeability, shale volume and water saturation were assigned to grid blocks using sequential Gaussian simulation (SGS). Finally, the Monte-Carlo simulation approach was used to rank the key variables affecting OGIP in the uncertainty and optimization process.

Flow based techniques were used for up-scaling reservoir properties into the coarse simulation grid. The full field simulation model was calibrated with buildup data and hydraulic fracture modeling of single wells. Production of the Doig channel from comingled wells was allocated systematically in order to achieve a good match of the gas production history and bottomhole pressures. Sensitivity analysis of fracture half length and its impact on ultimate gas recovery was investigated. This concludes with an integrated development strategy.

It is concluded that integration of multiple domains leads to a valid full field reservoir model which is critical in developing an integrated strategy, predicting reservoir performance and optimizing gas production.
Dual Porosity Typecurves for Shale Gas Reservoirs
Authors: Moghadam S. , Mattar L. , Pooladi-Darvish M.
Published: February 2011

Recent advances in the analysis of production data suggest that in shale reservoirs, a horizontal well with multiple hydraulic fractures creates a Stimulated Reservoir Volume (SRV). This SRV consists of matrix and fissures similar to a naturally-fractured system. Traditionally, dual porosity reservoir models have been used to describe the behavior of naturally-fractured reservoirs, and therefore these models can also be used to analyze the gas production from the SRV of shale reservoirs.

Often linear flow is the dominant flow regime in these reservoirs, and because of the low permeability, production takes place at high drawdowns (effectively constant wellbore flowing pressure). Accordingly, in this work, we develop typecurves for linear flow, constant flowing pressure, and transient dual porosity. First, we identify the different types of linear flow that may be seen in transient matrix-to-fissure interporosity flow, in the presence of a fully penetrating hydraulic fracture. Second, we provide practical criteria to differentiate between the types of linear flow. This allows us to determine if the reservoir can be treated as an equivalent homogeneous reservoir or if it should be treated as a dual porosity system.

In the paper, we generate dual porosity typecurves for various Lambda and Omega values, and convert them to a single curve that is equivalent to Wattenbarger's linear flow typecurve. We propose a work flow using this single curve, and we identify if and when it is possible to uniquely evaluate reservoir properties such as effective permeability and areal extent of the fissured system (SRV).
Effects of Nano Sized Metals on Viscosity Reduction of Heavy Oil/Bitumen During Thermal Applications
Authors: Hamedi Shokrlu Y. , Babadagli T.
Published: February 2011

Conventional (steam injection) and unconventional (electrical/electromagnetic heating) heavy oil/bitumen recovery methods require a high amount of energy. The efficiency of these methods can be increased by improving the energy transfer to the oil for viscosity reduction. It has recently been shown that micron-sized metal particles improve the efficiency of some ex-situ processes such as coal liquefaction and pyrolysis, heavy oil upgrading, oil shale recovery, and heavy oil viscosity reduction. This idea, with some modifications, can be applied to reduce the energy input of the aforementioned recovery methods for more economical heavy oil/bitumen production. The major contribution of the metal particles is expected to improve viscosity reduction by reducing the amount of the required energy. The objective of this work is to clarify the mechanics of additional viscosity reduction using nano-size metals during thermal applications through a series of experiments.

In the absence of electromagnetic fields, exothermic chemical reactions and thermal conductivity enhancement are the two important functions of metals to cause a reduction of oil viscosity. Two sets of experiments were conducted to investigate these mechanisms. Different metal types including iron, nickel and copper with different sizes and their different compounds were selected. The viscosity of oil samples, mixed with these particles, was measured. The tests were repeated at different temperatures. Also, the effect of the metal particles on heat transfer enhancement was examined. Nano-sized particles were found to have a remarkable effect on heat transfer through heavy oil.

The experiments provided a good understanding of the ongoing mechanisms that would lead to a viscosity reduction by the addition of metal particles. The concentration, type, and size of the particles were found to be highly critical on viscosity reduction. The optimal values of these parameters were identified. The results and observations are expected to be useful in further studies and applications as to the efficiency improvement of the thermal applications for heavy-oil/bitumen recovery.
Optimal Amount of Solvent in Solvent Aided Process
Authors: Gupta S. , Gittins S. , Sood A. , Zeidani K.
Published: February 2011

The Solvent Aided Process (SAP), described previously in literature, is an improvement to SAGD that promises to enhance the economics of bitumen/heavy oil recovery projects and reduce their impact on the environment. In SAP, a small amount of hydrocarbon solvent (such as a low molecular weight alkane) is introduced as an additive to the injected steam during SAGD. The viscosity of the oil thus is reduced due to solvent dilution in addition to heating. SAP can significantly improve the energy efficiency of SAGD, thus reducing the heat requirement. Cenovus's field trials of SAP, discussed elsewhere, have shown the practical upside of this process. Modeling predicts that the higher the amount of solvent used in SAP, the better is the performance (rates, energy intensity) of the recovery process. Besides rate of Bitumen production, economics of SAP depend on the availability and cost of solvent. Although the existing literature has discussed deterministic variations in solvent input, it is largely silent on how much solvent is the right amount of solvent in SAP.

This paper contains discussion of using optimal amount of solvent with steam in SAP. The discussion is based on modeling and compares performance of the scheme under various solvent injection strategies. It explores effect of temporal variation in the concentration of solvent at the vapor-liquid interface as well as of pulsed solvent injection on the performance of the process.
Cyclic Steam Injection With Solvents as Method of Thermal Recovery for Heavy and Extraheavy Oils: Laboratory Tests
Authors: Castro Y. E. , Veliz A. M. , Sanchez D. A. , Rodriguez M. M. , Rondon N. G. , Rivero S. , Cortez M. L.
Published: February 2011

Venezuela has the biggest reserves of heavy and extra heavy oils in the world. High viscosity of heavy and extra heavy oils is the main difficulty for its exploitation and production. Steam injection is a possible enhanced oil recovery (EOR) technique most widely applied to this type of oils based on temporary viscosity decrease. Commonly, it is used in Venezuela and Canada; however, factors as steam availability at field operations and low values of displacement efficiency achieved along the process by oil viscous forces have affected its possible use in the future.

Nowadays, PDVSA Intevep is evaluating the potential application of the method using some light oil cuts as solvents or additives which are from refineries located nearly to the fields under exploitation operations.

So far, static tests have been carried out by using methane, heavy oil from a Venezuelan field (9°API y 41500cP@43 °C) and solvents as light oil cuts (naphtha, kerosene) and two types of effluents from some refinery processes which will be named cut A and B along this investigation at saturated steam conditions. Displacement tests using displacement cells at reservoir conditions in porous media (253 °C, 400 psi, 30% porosity value and 4 Darcies, permeability) have also been performed in order to determine percentages of oil recovery.

Results indicated no net differences between the solvents selected during oil - solvent compatibility tests. Nevertheless, the effluents named 1 and 2 increased percentages of recovery factor notably along displacement tests obtaining values around 50 % in comparison to conventional displacement tests by using steam only. Hence, the use of this type of effluents which are cheaper than the light oil cuts selected is being recommended as potential application at field operations in Venezuela taking into account further studies as well as further technical and economical evaluations.
SWACO2 and WACO2 Efficiency Improvement in Carbonate Cores by Lowering Water Salinity
Authors: Aleidan A. , Mamora D. D.
Published: February 2011

We have performed a miscible CO2 flood study using heterogeneous carbonate cores and 31°API west Texas oil to evaluate oil recovery under four injection modes: simultaneous water and CO2 (SWACO2), water alternating CO2 (WACO2), continuous gas injection (CGI), and waterflood (WF). For WACO2 and SWACO2 injection modes, three salt concentrations are used: 0, 6, and 20 wt. %. For WF, two salt concentrations are used: 0 and 6 wt. %.

The experimental results may be summarized as follows: For injected water with 20 wt. % salt concentration, the oil recoveries for SWACO2 and WACO2 are 81 and 74 % oil initially-in-place (OIIP), respectively. For 6 wt. % salt concentration, the oil recoveries for SWACO2 and WACO2 increased to 90 and 86.5% oil initially-in-place (OIIP), respectively. With injected pure water (0 wt. %), the oil recoveries for SWACO2 and WACO2 increased to 98 and 92 % OIIP, respectively. The waterflood oil recovery remains the same at 54% for both salinity levels indicating that dissolved CO2 is the critical factor in oil displacement. Literature data suggests that CO2 solubility in water increases when salinity of the injected water is reduced. The low salinity water with CO2 appears to increase the microscopic oil displacement efficiency.
Evaluation of the Potential of Microbial Conversion Process of CO2 Into CH4 by Investigating the Microorganisms in High CO2 Content Oilfield
Authors: Sugai Y. , Purwasena I. A. , Sasaki K. , Fujiwara K.
Published: February 2011

CO2 sequestration into depleted oil reservoirs has been expected to be a method of reducing CO2 emission. We focus on the in-situ conversion of CO2 into CH4 by hydrogenotrophic methanogens which inhabit oil reservoirs universally. This conversion process has not only the potential of reducing CO2 emission but also the potential of reproducing natural gas deposit in reservoirs. The hydrogenotrophic methanogens need not only CO2 but also H2 to produce CH4, therefore, H2 should be supplied to them in reservoirs for this process. It has been reported there are several kinds of bacteria which produce H2 by degrading parts of crude oil in reservoirs. In this study, the potential of this conversion process was evaluated by investigating the habitation of these bacteria in a high CO2 content oilfield. Reservoir brine samples were extracted in a high CO2 content oilfield. Concentration of CO2 and CH4 in the gases which were produced from reservoirs in the oilfield was 35–60% and 20–40% respectively. Microbial genomic DNAs were extracted from reservoir brine and their nucleotide sequences were analyzed to identify the species inhabiting the brine. Thermotoga naphthophila and Thermoanaerobacter sp. which are well known as oil-degrading and hydrogen-producing bacteria were detected as a dominant in the brine. Moreover, Methanobacterium sp. and Methermicoccus sp. which are well known as hydrogenotrophic methanogens were also detected in the brine. It is assumed that these hydrogenotrophic methanogens live in symbiosis with oil-degrading and hydrogen-producing bacteria and convert CO2 into CH4 in the reservoirs. In addition, culture experiments of the microorganisms which belonged same genus or same family of the above microorganisms were carried out under the reservoir conditions. Both hydrogen production and methane production were observed in the experiments. These results indicate that the in-situ microbial conversion process of CO2 into CH4 has high potential.
Energy Efficiency in the Electrical Heating of Methane Hydrate Reservoirs
Authors: Callarotti R. C.
Published: February 2011

In this paper we analyze the production of methane gas from methane hydrate deposits when heat is supplied by an electrical heater located in the reservoir. The reservoir is assumed to have cylindrical symmetry of variable external radius and variable thickness. By means of the enthalpy method we determine numerically the transient response of this system under a constant applied electrical power supplied to a cylindrical heater located at the center of the reservoir and at different depths. We determine the volume of methane hydrate that will melt and the energy equivalent of the gas thus produced. The energy efficiency of the heating process is obtained as the ratio of the gas equivalent energy to the applied energy.

In the calculations the heater temperature is maintained constant by a down-hole controller, so as to avoid the conversion into steam of the water produced. For different levels of applied electrical power, at a given heater temperature, we find that there is an optimal value of heater length where the ratio of the equivalent energy produced to the energy input is a maximum.

The energy efficiency of this heating process is the critical factor in determining the feasibility of an electrical heating production scheme.
Assessment of the Distribution of Technically-Recoverable Resources in North American Basins
Authors: Cheng K. , Wu W. , Holditch S. A. , Ayers W. B. , McVay D. A.
Published: February 2011

As gas production from conventional gas reservoirs in the United States decreases, the industry is turning more to the exploration and development of unconventional gas resources (UGR), especially shale gas reservoirs. This trend is expanding quickly worldwide. Unlike in many mature North American basins, where resources and reserves are well characterized, the volume of unconventional gas resources is generally unknown in most basins outside North America (frontier basins). Therefore, a comprehensive investigation and evaluation of North American unconventional gas resources is significant not only for identifying and understanding the quantitative distributions of recoverable UGR in North American basins, but also for estimating the volume of UGR in frontier basins. Our investigation of North American unconventional gas resources is based on the resource triangle concept, which implies that all natural resources, including oil and gas, are distributed lognormally in nature. Martin et al. (2010) described a methodology to estimate values of total recoverable resources (TRR) for unconventional gas reservoirs. In their work, the authors combined estimates of production, reserves, reserves growth, and undiscovered resources from a variety of sources into a logical distribution. They used data from 8 basins in North America to demonstrate their results. We have expanded the work of Martin et al. (2010) to include data from a total of 25 basins in North America. The results show that the overall ratio of TRR in unconventional gas reservoirs to those in conventional oil and gas reservoirs in the 25 basins is approximately 4 to 1. This means that for every Tcfe of oil and gas produced from conventional reservoirs, one could expect another 4 Tcfe to be technically recoverable from unconventional gas reservoirs in the same basin. This observation can help companies assess the potential of unconventional gas resources development in North American basins and in frontier basins worldwide.
A Simulation Study of a Cyclic Steam Stimulation Pilot in a Deep Carbonate Heavy Oil Reservoir in Oudeh Field, Syria
Authors: Li M. , Astete E. , Wang H.
Published: February 2011

The Oudeh Shiranish reservoir in Syria contains 5.1 billion bbls of 12-16 °API crude oil. However primary recovery factor is estimated to be only 5 to 7% of the original oil in place. To increase oil recovery, waterflood, VAPEX, microbial treatment and cyclic steam stimulation (CSS) were examined. Eventually, CSS was selected for a pilot test despite the depth of the reservoir, approximately 1600 meters, was deeper than most successful CSS projects in the world.

The CSS pilot was implemented in September 2006 and suspended in November 2009. The project expanded from 2 to 24 wells. Low steam quality at the bottom of the well proved to be the most prominent challenge due to a combination of heat loss in the wellbore and relatively low steam injectivity. Only hot water reached the bottomhole when steam was injected through casing. Injection into tubing improved steam quality. Vacuum insulated tubing (VIT) produced the best, increasing steam quality to between 20 and 40% at a wellhead steam quality of 80% and an injection rate of 200 m3 CWE/day. The high pressure required to inject into the Shiranish reservoir at close to or higher than initial reservoir pressure conditions means that the latent heat of vaporization is low, compared to the typical CSS injection pressure, resulting in a less effective heating process.

In the study, a new thermal simulation model was developed to examine history-matching parameters, match the well and pad performances and optimize operations if the pilot were to be continued. Excellent history matches were achieved. Forecast indicated that Shiranish CSS performance was positive and could increase oil recovery by up to 100% over cold production.
Analytical Solution for Gas Production from Tilted Gas Hydrate Reservoir
Authors: Hamed Tabatabaie S. , Pooladi-Darvish M.
Published: February 2011

The declining conventional hydrocarbon resource and increase in energy demand has encouraged the development of unconventional gas resources. One specific type of unconventional gas is the natural gas hydrate. The substantial size of the hydrate resource is a motivating factor in its development. In the early phases of development of hydrate reservoirs data is limited and a large number of sensitivity studies are required. Efficient and accurate analytical models are suitable for such sensitivity studies. One of such solutions is presented in this work.

An analytical solution is developed to model rate of gas generation and hydrate recovery when gas is produced from an inclined hydrate-capped gas reservoir where the geothermal gradient is accounted for. As a result of the difference in temperature within the hydrate column, the size of the decomposing area increases with continued production.

Development of the analytical model of this work is based on a material balance equation that is combined with the solution for the temperature of the decomposed zone and hydrate equilibrium curve. The three equations are solved simultaneously for the gas generation rate. To validate the assumptions made in the development of the analytical model, a numerical simulator was used. The effects of different reservoir parameters on the reservoir performance were investigated by performing sensitivity analysis. The sensitivity results show how a steeper reservoir that extends closer to the base of permafrost leads to less recovery, or how a thicker hydrate cap could maintain the reservoir pressure for a longer time.

The model developed in this study can be used as an approximate engineering tool to evaluate the role of hydrates in improving the productivity and extending the life of tilted hydrate-capped gas reservoirs.
Integrated Assessment of CO2-Enhanced Oil Recovery and Storage Capacity
Authors: Zhang Y. , Zhang L. , Niu B. , Ren S.
Published: February 2011

CO2 enhanced oil recovery (EOR) has been used as a commercial process for enhancing oil recovery since the 1970s, whereas limited field applications of CO2 storage were undertaken only recently. In practice, considerable reservoir engineering design effort was made to reduce the total amount of CO2 required to recover each barrel of oil in a CO2 EOR project. For CO2 storage, however, the objective is to increase the amount of CO2 left behind at the end of the injection process; therefore, the approach to the design question changes. Consequently, optimization of CO2 EOR and CO2 storage processes differs significantly from the current CO2 injection practices. In this paper, techniques were developed to systematically assess CO2 EOR and storage capacity in a hydrocarbon reservoir selected for a demonstration project. More specifically, oil recovery was assessed and determined under miscible conditions, while CO2 storage capacity was determined by using an estimation model improved in this study. In addition, economic analysis was conducted, assuming that CO2 was captured from a chemical plant and transported 120 km to the oilfield. It is found that the geological framework is suitable for CO2 storage in the selected reservoir and that, due to a favourable CO2 miscible displacement mechanism, high oil recovery and storage capacity can be achieved, which leads the demonstration project to be economically profitable if prices of crude oil and CO2 remain above certain values.
Integrated Steam Generation Process and System for Enhanced Oil Recovery
Authors: Betzer-Zilevitch M.
Published: February 2011

Steam injection into deep underground formations has proven to be an effective method for EOR facilities producing heavy oil from non-minable oil-sand formation. It is typically done through SAGD, Steam Drive or by CSS. Most facilities generate waste liquids and consume natural gas. This paper proposes a method and system for producing steam for extraction of heavy bitumen with zero liquid discharge and with the ability to consume low grade fuel. The presented system includes "Direct Contact Steam Generation" (DCSG) used for direct heat transfer between combustion gas and contaminated liquid phase water for steam generation. The DCSG can be integrated into a commercially available pressurized boiler or gasifier for internally mixing the low quality water with the combustion gas and transferring the liquid water to gas. The DCSG can also be a separate entity, allowing the use of existing atmospheric boilers (like OTSG or industrial boilers). To recover the heat and the water from the DCSG discharge and to use it to generate additional BFW (Boiler Feed Water) for steam generation, a commercially available water distillation unit can be used: like an evaporator, MED (Multi Effect Distillation), MSF (Multi Stage Flash) or MVC (Mechanical Vapor Compressor). The water treatment plant discharge brine is recycled and consumed by the DCSG. Another advantage of the process is its ability to consume highly contaminated oily water and feed them directly to the DCSG. This capability simplifies the oil-water separation and reduces the amounts of chemicals normally used in this processes. The presented system can be integrated into an existing project as a new phase, with the advantage that all the liquid waste generated by old phases can be consumed by the DCSG providing an overall ZLD facility. The sludge waste of an existing hot or warm lime softener water treatment plant can be recycled to the combustion stage or to the DCSG and used to remove sulfur with petcoke or coal fired systems. Another advantage of the proposed solution is that any field facilities (like the pads, injection and production wells) will be unchanged, and will be similar design to standard well known facilities. The paper shows a clear solution to achieve an effective ZLD system that can use low grade water and low grade fuel.
Laboratory Investigation of Novel Oil Recovery Method for Carbonate Reservoirs
Authors: Yousef Ali A. , Al-Saleh Salah , Al-Kaabi Abdulaziz , Al-Jawfi Mohammed
Published: February 2011

The impact of brine salinity and ion composition on oil recovery has been an area of research in recent years. Evidence from laboratory studies supported by some field tests targeting mainly sandstones, has distinctly shown that injecting low salinity water has a significant impact on oil recovery. Although, the potential for carbonates has not been thoroughly investigated, some reported studies have excluded carbonates from this effect. The main objective of this paper is to investigate the potential of increased oil recovery by altering the salinity and ion composition of the injection water for carbonate reservoirs, define the recovery mechanisms, and eventually transform the emerged trend to full-fledged reservoir technology.

This paper presents the results of a laboratory coreflooding study conducted using composite rock samples from a carbonate reservoir to investigate the impact of salinity and ionic composition on oil/brine/rock interactions, and eventually on oil recovery. The experimental parameters and procedures were well designed to reflect the reservoir conditions and current field injection practices, including reservoir pressure, reservoir temperature, salinity and ionic content of initial formation water and current types of injected water. Also, this study provides detailed discussion and interpretation for potential mechanisms.

The experimental results revealed that substantial tertiary oil recovery beyond conventional waterflooding can be achieved by altering the salinity and ionic content of field injected water. The new emerged trend is distinct from what has been addressed in previous reported studies on topics of low salinity waterflooding for sandstones, or seawater injection into high temperature chalk reservoirs. On the subject of recovery mechanisms, the results showed that altering the salinity and ionic composition of the injected water has a significant impact on the wettability of the rock surface. This was also confirmed by nuclear magnetic resonance (NMR) measurements. The results, observations, and interpretations addressed in this study provided compelling evidence to suggest that the key mechanism for the emerged trend is wettability alteration.
Experimental Study of the Impact of Shear Dilation and Fracture Behavior during Polymer Injection for Heavy Oil Recovery in Unconsolidated Reservoirs
Authors: Zhou Jian , Dong Yufei , de Pater C. J. , Zitha Pacelli L.
Published: February 2011

Polymer flooding provides a better sweep compared with water flooding, but there is concern about maintaining sufficient injectivity. Longer fractures could provide injectivity, but pose a risk for early break-through and containment. In addition, shear dilation of unconsolidated sand is also expected to improve permeability and injectivity. Shear dilation causing absolute permeability enhancement was observed in tri-axial tests. The relationship between propagation pressure and confining pressure was determined in unconsolidated sands by a series of physical model tests. The accuracy of the minimum in-situ stress determination was also investigated in unconsolidated sands. The results demonstrated that there is a small enhancement of absolute permeability due to dilation of unconsolidated sand and they do have a difference in absolute permeability between stress states for increasing and decreasing effective stress. Besides, the geometry of fractures induced by viscous fluids in an unconsolidated formation is a dominantly planar fracture, although it is very tortuous. In view of isotropic stress in the horizontal plane, multiple fractures were induced in several directions.
Intelligent Oilfield Considerations for New Developments Offshore Abu Dhabi
Authors: Cobb David , Forster Matthew , Kirkman Matthew
Published: February 2011

ADMA-OPCO is currently pursuing the development of several undeveloped structures offshore Abu Dhabi. These fields, some of which have been appraised over the last 30 years, are currently being evaluated and moved forward for full field development. As part of this development we are actively incorporating Intelligent Oilfield concepts into these development plans and this paper seeks to highlight some of the key considerations and assumptions being integrated into ADMA-OPCO’s philosophy for these developments.

The next generation of oilfields is looking at these concepts to apply this advanced technology to: Enhance hydrocarbon recovery;Improve the safety for our Offshore Installations (by investigating new ways of working and opportunities to reduce the manning of these Operations);Reduce the Operating Costs (by improving the overall operating efficiency);

It has been documented (Dickens et al. 2010) that by improving the down hole surveillance and control we may significantly enhance our ability to improve recovery in these large offshore fields. The challenges ADMA-OPCO faces offshore Abu Dhabi is that we are dealing with a high number of complex wells, to ensure adequate drainage and optimum flux rates, to enhance overall recoveries, from these difficult reservoir intervals. The optimal utilization of technology (for the applications of down hole monitoring and control) is complex as the number of wells and increasing complexity in well construction, is driving the drilling Capex higher.

Current development plans in these fields show that a significant component of the field development capex is associated with the well construction costs, a significantly greater proportion of Capex than in conventional offshore developments. This is, due to the relatively lower facility costs associated with shallow water development in the Gulf. Hence optimization of well construction costs is a key component of successful delivery of the new fields. The rationalization of well complexity and organizational capability is an additional component in actively managing the increased risk associated with these non-traditional wells.

Additionally we screened the systems, processes and infrastructure required to ensure optimal delivery of the real time monitoring capability and decision making capability that this technology can unlock. This paper will seek to share how ADMA-OPCO plans to move the field development concepts forward in the project life cycle and how we look to leverage world-wide learning in bringing this technology into offshore Abu Dhabi and details some of the challenges and opportunities that occur as we move forward with these concepts.