bluuebunny/crossref_metadata_2025 huggingface dataset:
Long-Term Calcium Phosphate Cement for In-Situ Combustion Project
Authors: Mac Fuenmayor , Diego Orozco , Hollman Nieto , Javier Urdaneta , Alberto Gomez , Brothers Lance , Herman Pedrosa
Published: June 2014

The increasing demand for energy has increased the need for production of hydrocarbon. As a result, operators have exploited more difficult reservoirs (e.g., deeper wells, remote areas, mature depleted fields, and heavy oil reservoirs). Traditional methods are not sufficient for producing heavy oil; therefore, over time, enhanced recovery methods have been researched and developed.

In-situ combustion (ISC) is the oldest thermal-recovery technique. It has been used for more than nine decades for many successful projects. This method is basically the injection of an oxidizing gas (air- or oxygen-enriched air) to generate heat by burning a portion of resilient oil. Most of the oil is driven toward the producers using a combination of gasdrive, steam, and waterdrive.

High temperatures and the presence of corrosive gases involved during the ISC process can present significant challenges during well isolation.

Phosphate cement is a unique system capable of resisting corrosive attack, maintaining low permeability at high temperatures, and resisting the attack of carbonic acid.

One of the primary challenges was developing a special phosphate cement slurry capable of setting at low temperatures to minimize the waiting on cement (WOC) as well as developing properties sufficient for resisting future stresses. A special sodium aluminate thixotropic additive was used for the first time to react chemically with the pH of this special cement system to develop a quick and high compressive strength.

More than nine wells have been cemented with this system in Colombia with good results. These wells have been subjected to different stresses (production, steam injection, and ISC). This paper presents the successful application of advanced non-Portland cement slurry within the Quifa heavy oil reservoir in Colombia utilizing an ISC enhanced recovery method
Hybrid High Build Rate RSS Improves Challenging Directional Control in a Soft Abrasive Drilling Environment in Oman Drilling Operation
Authors: Al Bardisi Tareq , Akhmetov Roustam , Sanderson Martin , Adly Essam , Escamilla Barton , Andreasen Greg , Noureldin Ali , Al Habsy Hilal
Published: June 2014

A heavy oil field, located in south-central Oman with unconsolidated sandstone reservoirs represents many drilling challenges. Past drilling with conventional mud motors in the field was associated with many drilling risks, including poor wellbore quality, difficulty steering, inadequate hole cleaning, and differential sticking. These risks resulted in extra correction trips, lost-in-hole bottomhole assemblies, sidetracking, and redrilling entire sections.

The field's current development plan is based on the factory drilling concept, which is driven by the number of wells that are required to be delivered in a given year. This requirement places a great amount of importance on drilling time. The average time from spud to spud in the field is 8 to 9 days; any additional trips have a large impact on the total number of wells delivered. In addition, due to the nature of the heavy oil sandstone reservoir, steam injection is required to enhance oil recovery. It is therefore critical to place the lateral hole section of the well in the center of the target corridor to avoid early breakthrough. To compound this, the fluvial nature of the reservoir, tight surface location constraints, and shallow reservoir true vertical depths (TVDs) have added to directional complexity.

To address the main technical challenges of directional assurance and greater drilling efficiency, the operator and service company explored alternative ways of drilling the 8.5-in. reservoir hole section, and this hole section was be the focus of our analysis.

The learning curve experienced in finding an answer for the technical challenges of directional control and drilling efficiency can be broken down to four distinct phases: Phase 1 in 2008: Conventional motorPhase 2 in 2009: Introduction of point the bit rotary steerable system (RSS)Phase 3 in 2012: Introduction of high dogleg severity (DLS) rotary steerable system (RSS), a hybrid design (i.e., push-the-bit and point-the-bit system)Phase 4 in 2013: Enhance drilling efficiency

Extensive data gathering and log analysis provided a better understanding of the main issues and ultimately led to the root cause. The analysis provided a clear solution, which was that a high-build-rate-capable RSS was needed to overcome the directional tendencies and deliver the planned well trajectory to the final total depth (TD) in one run to reduce the average well time.
Using Multiple Objective Optimization for SAGD Simulation Numerical Tuning
Authors: Li Heng , Yang Chaodong , Mirzabozorg Arash , Fedutenko Eugene , Nghiem Long
Published: June 2014

Numerical tuning has shown to be an effective approach to improve computational performance of simulation models, especially complex large-scaled ones. One purpose of numerical tuning is to find a set of numerical parameters that make the simulation run faster with less material balance error. However, in many cases, these two objectives are conflicting with each other. The most common way to tackle this problem is to create an aggregated global objective function, which is the weighted average of the two objectives, and then try to optimize it using a single objective optimizer. In this study, Multiple Objective Particle Swarm Optimizer (MO-PSO) is applied to conduct numerical tuning on a sub-model of a real field SAGD case study. MO-PSO tries to reduce the simulation run time, and the material balance error simultaneously. The results obtained by MO-PSO are compared with that of single objective particle swarm optimizer (SO-PSO). Results showed that MO-PSO is much more effective and efficient in finding Pareto front compared with SO-PSO. MO-PSO eliminates the usage of any weighting factor, which makes it much easier to set up and avoid biased searching results. In addition, MO-PSO converges to optimal solutions much faster than SO-PSO for this study. SO-PSO with well-defined aggregated weighted global objective function can also find a good Pareto front, but inappropriate weighting factors in the aggregated global objective may lead to biased solutions.
Research on the Effect of Non-condensable Gas and Viscosity Reducer for Better SAGD Performance
Authors: Lu Chuan , Liu Huiqing , Liu Qian , Lu Keqin , Wang Limei
Published: June 2014

Steam Assisted Gravity Drainage (SAGD) is widely used as an in-situ technology to recover heavy oil and bitumen. But due to serious heat losses, large energy requirements and enormous CO2 emissions, pure SAGD may not be sufficiently efficient to allow economical production.

The main objective of addition of viscosity reducer is to couple viscosity reduction capability of heat and surfactant. It strengthens the formation of emulsions of O/W type that have much lower viscosity than the oil from which they are formed, and enhances oil production under the same amount of steam to make the thermal process more profitable. With regard to the non-condensable gas, its distribution and movement is essential for the expansion of the steam chamber.

In this paper, the performances of a set of selected viscosity reducers under high temperatures are firstly evaluated. Then based on a high temperature and high pressure two-dimension physical model, different injection processes are conducted to study the separate and combined effect of nitrogen and viscosity reducer on the vertical and horizontal expansion rates of steam chamber. The results show that the injection of nitrogen helps the steam chamber expand more quickly in the horizontal direction. And the combination of viscosity reducer and nitrogen makes the steam chamber expand more quickly than the pure SAGD and Nitrogen-SAGD processes. The following sand pack physical models are conducted to further investigate the mechanisms of viscosity reducer and nitrogen in porous media, such as the steam profile correction relying on the blocking capacity of emulsions, heat loss reduction and the combination effect of gas expansion and viscosity reducer on the displacement of residual oil. In addition, numerical simulations are conducted to demonstrate the feasibility of SAGD assisted by viscosity reducer and nitrogen in Du 84 ultra-heavy oil reservoir. Besides optimizing operation parameters, such as nitrogen steam ratio, effective nitrogen injection volume, interval time between viscosity reducer injection and nitrogen injection, the study results show the effect of this technology on the improvement of thermal oil recovery.

In summary, this study is beneficial for the application of viscosity reducer and nitrogen in the process of SAGD.
An Integrated Approach to Building History-Matched Geomodels to Understand Complex Long Lake Oil Sands Reservoirs, Part 1: Geomodeling
Authors: Zhang Xingquan Kevin , Feizabadi Seyed Ali , Yang Peter
Published: June 2014

At the Nexen Long Lake in situ steam-assisted gravity drainage (SAGD) oil sands recovery project, the bitumen-saturated reservoir is in the Lower Cretaceous McMurray Formation. The main depositional environment in the reservoir unit is fluvial-estuarine meandering channels. Stacked channel deposition exhibits a high degree of variability both vertically and laterally over short distances and depositional complexity occurs at many scales. Many papers have been written on characterizing oil sands deposition geologically or geostatistically. However, complete characterization cannot be achieved at all scales due to the degree of complexity.

Building a history-matched geomodel can be very time consuming and very challenging in complex reservoirs such as in Long Lake, where the Quaternary (Gregoire) Channel, collapse features, top gas and top water, lean zones, as well as shale barriers and baffles, contribute to the complexity. This paper presents a practical geological modeling approach used at Nexen to quantify uncertainties of reservoir properties. This approach has been validated by history matching and prediction. The solution is based on the integration of all available geology, geophysics, petrophysics, reservoir engineering, and production information. Using the proposed solution, the number of modeling iterations and the time required to achieve the desired objectives of history matching and prediction have been significantly reduced.
The Role of Water Soluble Species in Bitumen Recovery from Oil Sands
Authors: Swiech Weronika M , Taylor Spencer E , Zeng Huang
Published: June 2014

It has been considered that water soluble species can influence the recovery of bitumen by having an effect on parameters such as wettability or surface charge, thereby altering interactions between oil sand components.

This work considers interactions occurring between representative water soluble acid species and their potential effect on bitumen recovery. It considers the characterization of oil sands components in terms of physicochemical and dielectric properties. Dielectric properties arise from electronic and atomic polarization or dipole, ionic or dielectric relaxation mechanisms. Organic compounds present in the water in the natural environment and also considered to be in oil sand reservoirs are functionalized with chemical groups that undergo chemical processes dependent on the physical conditions of the environment.

The study focusses on a combination of artificially prepared systems analyzed using a variety of techniques, including dielectric spectroscopy, UV-Vis spectrophotometry, sedimentation analysis and adsorption isotherms. Dielectric measurements were undertaken on a range of artificially prepared samples analyzed at moderately low frequencies (10-2 to 107 Hz), which, in the first part of this study, revealed strong, regular dependencies on the composition of the systems, enabling effects of adsorbed species to be discerned. These results revealed information on the properties of a range of compounds naturally present in the oil sand or induced during processing. Colloid and interfacial properties were probed through conductivity, surface tension and zeta potential measurements. With reference to the literature and the new results, an attempt has been made to propose the mechanism representing the interactions between the water soluble compounds and other components present in oil sands such as solids and bitumen, which influence not only heavy oil recovery but also produced water treatment.
Improved Isenthalpic Multiphase Flash Calculations for Thermal Compositional Simulators
Authors: Heidari M. , Nghiem L. X. , Maini B. B.
Published: June 2014

In thermal compositional reservoir simulators that use energy as a primary variable, thousands to millions of isenthalpic multiphase flash calculations must be performed to calculate temperature, phase splits and compositions for different grid blocks during the simulation. Development of a robust and fast isenthalpic multiphase flash calculation method is necessary to improve the efficiency of such simulations.

A new isenthalpic multiphase flash calculation is described in this paper. The flash calculation method uses a modified Rachford-Rice monotonic objective function and the negative flash concept for phase distribution and phase identification. Therefore phase stability analysis is not necessary. The formulation and algorithm of the new method are presented in detail. This method is able to handle difficult situations such as narrow boiling point regions and phase appearance and disappearance, which are dominant in thermal processes. The current method encounters no difficulty in the latter situations unlike stage-wise isenthalpic flash calculation methods.

After the accuracy of new method was compared and verified against current algorithms used by the industry, it was also tested for robustness and speed. The results show promising performance compared to the current methods. This proposed method is not sensitive to the initial guess for temperature. As a matter for fact, in all of the test cases in this study, the same temperature was used as the initial guess. A poor initial guess for temperature only requires more iterations to reach the solution.
Forward Modeling of SAGD-Induced Heave and Caprock Deformation Analysis
Authors: Shen Luyi , Singhroy Vern , Samsonov Sergey V.
Published: June 2014

This study focuses on the investigation of the mechanism behind surface heave induced by thermal recovery. Injection of steam into oilsand reservoirs results in changes in temperature and pore pressure within the subsurface. These changes can induce a reduction of effective stress, which provides initial containment of bitumen. Irreversible shear/tensile deformation of the caprock and overburden might be one of the unwanted consequences of such process.

We developed a work flow incorporating the Finite Difference Method (FDM) and Finite Element Method (FEM). Heat and fluid flows are computed using FDM with CMG-STARS and elastic/plastic deformation estimations are done through Abaqus FEM simulation software. The Mohr-Coulomb yield criterion and the non-associated flow rule is used to assess the plastic failure in the reservoir and caprock. This work flow is used to assess the impact of the SAGD process on the integrity of caprock.

The geomechanical model is calibrated with surface deformation measurements. Parameter search is performed to study how geomechanical parameters influence the expression of reservoir deformation at the surface. The uncertainty associated with the modeled results shows the need for a more refined geomechanical model, considering the heterogeneous nature of geological structure in the region of interests.
The Effects of Minerals on Heavy Oil and Bitumen Chemistry When Recovered Using Steam-Assisted Methods
Authors: Montgomery Wren , Sephton Mark A. , Watson Jonathan S. , Zeng Huang
Published: June 2014

The production of gaseous sulfur-containing species during the steam-assisted recovery of heavy oil and bitumen have important consequences for both economics and safety. Factors such as the effects of mineral matrices require laboratory data to produce accurate models. To study mineral effects on gas production we studied a well-characterized oil-containing core and the isolated crude oil from that core. The samples were run at 250–300°C in the continued presence of liquid water for 24 hours. The reaction products of all experiments include gases, oil flotate, oil sinkate, water-soluble products, and water-insoluble residues. All reaction products were studied with a variety of analytical techniques, including FTIR spectroscopy, chromatographic fractionation (SARA analysis), GC-MS, pyrolysis GCMS and GC-FPD/TCD. These techniques were applied to whole oil, maltenes and asphaltene fractions. Physical properties including viscosity and density were also measured. Our data provide insights into the physical and chemical consequences of steam assisted recovery of heavy oils and bituments from sedimentary rock reservoirs and reveal that geological and geochemical context is an essential consideration.
ESP Optimization in an Extra Heavy Oilfield: A Case Study in Colombian Llanos Basin
Authors: Lopez Uribe J. , Jiménez Morales G.
Published: June 2014

The experience of working with extra-heavy oil producing wells profitably requires the use of available technologies to the limits of their capabilities. Due to its heavy use of electricity, the Electrical Submersible Pump (ESP) has often proven unsuitable for fields producing high-viscosity fluids. However, in some cases, given the conditions downhole and fluid behavior, along with technological changes, it has been possible to use ESPs at moderate cost.

Exploitation today has become technically and economically feasible for reservoirs in upper or lower layers that were previously uneconomical given lifting, transportation and marketing costs.

Previously discovered resevoirs in the Llanos Basin of Colombia were considered of no commercial value given the characteristics of its oil (higher viscosities to 1,000 cps at 60° F /14.7 psia and API gravities less than 10°). The Operating Companies of the same blocks discovered other, more easily exploited oil reservoir units. These oilfields, now in their mature stages, have high production costs because of the inevitable increase in water cut and/or decreased pressure. This has spurred to the use of existing infrastructure and advances in technology for lifting, processing and transportation of heavy and extra-heavy oil reservoir units already discovered.

There have been several challenges in developing extra-heavy oil wells, such as organic precipitation, presence of scales, strong emulsions and high GOR.

ESP technology has advanced in the extraction of large fluid volumes, smaller stage diameters, metallurgy resistant to corrosion and abrasive solids, stronger shafts, and conditions of high pressure and high temperature. However, there are very few developments in sustainable extraction of heavy oil and extra-heavy oil.

This article describes an example of implementing the Electro Submersible Pump as a feasible method for artificial lift in wells producing extra-heavy oil.
Evaluation of Artificial Lift Modes for Heavy Oil Reservoirs
Authors: Mali Prasanna , Al-Jasmi Ahmad
Published: June 2014

Exploitation of heavy oil fields in Kuwait Oil Company (KOC) has been a challenging task. Both, cold and thermal methods are planned to produce these fields judiciously. Crude oil API gravity is 10-12. Well depth is from 700 to 3000 feet. Expected variation in production rate is from 30 - 300 bbl/d for cold production. With thermal application, envisaged range of liquid production rate is from 100 – 1000 bbl/d. Therefore, it is important to evaluate different artificial lift modes, to produce these heavy oil fields.

In this regard, application of various artificial lift modes, such as PCP, SRP, ESP, ESPCP, Metal PCP, etc., which can be used to produce heavy oil fields, under cold and/or thermal production pattern, are studied and are outlined in this paper.

With regard to this feasibility study, for cold heavy oil production, pilot of conventional PCP technology is carried out. Liquid rates of 30 - 300 bbl/d are achieved, when PCP technology, is tested for few wells, for cold heavy oil production. For heavy oil thermal production, pilot of ‘Metal PCP’ technology is carried out, with cyclic steam injection in place. Peak liquid production rate of 460 bbl/d is achieved, when metal PCP technology is tested in one well. The paper describes pilot methodology of these pilots. Results of both these pilots are encouraging. This has resulted in planning to use both these technologies, to produce heavy oil fields, on large scale basis.

Thus, the paper can be used as reference, to evaluate different lift technologies to produce heavy oil fields. It is inferred from the feasibility study that conventional PCP and metal PCP are emerged as desirable lift technologies, to produce heavy oil fields. Successful pilot implementation of these technologies, has further justified utility of these technologies, for exploitation of heavy oil fields.
Nitrogen Foam Anti-Edge Water-Incursion Technique for Steam Huff-Puff Wells of Heavy Oil Reservoir With Edge Water
Authors: Wang Jiexiang , Wang Tengfei , Yu Yingjun , Chen Zheng , Niu Zhiwei , Yang Changhua
Published: June 2014

The cyclic steam stimulation is an important thermal recovery technique which is used to develop heavy oil reservoirs. However, the development effectiveness is limited in steam huff-puff wells of heavy oil reservoir with edge water because of the sharply increased water cut caused by the incursion of edge water. An experimental device, which can simulate edge water and steam stimulation process, was designed on the basis of steam flooding device to investigate the nitrogen foam anti-edge water-incursion technique. The designed device includes 3 subsystems: reservoir physical simulation subsystem, edge-water simulation subsystem and fluid injection subsystem. The effect factors and application conditions of the technique were investigated, and the results showed that the effect of the technique was influenced by reservoir water-flooded degree, edge water energy and crude oil property significantly. This technique is more suitable for seriously water-flooded reservoirs whose cycle water cut is no less than 80%, and the reservoir edge water energy and heavy oil viscosity should be moderate. As for Henan heavy oil reservoir, the optimum edge water pressure is 4MPa, and the oil viscosity is less than 5000mPa·s at the reservoir temperature (stock tank oil). The optimum injection pattern of the technique is N2 slug – nitrogen foam slug – steam. Pilot tests were conducted based on experimental results. The operation success rate is 100%, the average cycle water cut is reduced by 23%, and the average cycle oil production is increased twice. In view of the test result, this technique is a successful measurement to inhibit the water incursion and enhance the oil recovery of steam huff-puff wells with edge water.
Evaluating the Importance of Geomechanical and Reservoir Properties When History Matching 4D Seismic Data in SAGD Wells
Authors: Hiebert Allan , Pathak Varun , Lifshits Gary , Kumar Anjani
Published: June 2014

It is becoming increasingly common to use 4D Seismic surveys on SAGD projects to characterize the steam chamber size, shape and growth. The use of this type of survey in history matching SAGD simulation models has also grown significantly, allowing engineers to match not only the volumes, temperatures and pressures, but the shapes of the steam chambers as well. In the authors' experience, however, before 4D Seismic surveys can be used confidently to history match the steam chamber shapes, we need to understand what 4D seismic represents. Prior proposals suggest steam or gas chamber volume, stress change volume or temperature change volume. To investigate this, the current study examines the impact of various physical property changes impacting the surveys (in particular, geomechanical effects), so that the appropriate 4D seismic history matching criterion are established.

To determine how the above factors impact the 4D seismic surveys, this study investigates the relative impact of various property changes that occur in-situ during the SAGD process, with the intent to determine what changes have the biggest impact on seismic velocity. A number of SAGD simulation runs were conducted using typical oil sands geology with fully coupled geomechanics. Afterwards, the change in pressure-wave velocity and shear-wave velocity at the simulation grid blocks at various times during the simulation was calculated. The property changes of temperature, pressure, stresses, saturations and fluid properties were also calculated, and then categorized in terms of the significance each factor has to the 4D Seismic data. This categorization serves to identify the appropriate SAGD history matching criterion, to improve the quality, confidence and predictability of a SAGD simulation model.
Solvent-Assisted Start-up of SAGD Wells in Long Lake Project
Authors: Ahmadloo F. , Yang P.
Published: June 2014

In oil sands in situ operations using steam-assisted gravity drainage (SAGD), achieving effective communication between the injector and producer with a reasonable conformance is crucial for the success of SAGD conversion and the following ramp-up phase. The start-up operation normally relies on heat conduction phenomena for establishing communication between the wells. For oil sands reservoirs containing extremely high viscosity bitumen, establishing the temperature profile required for SAGD conversion using conduction as the only heating mechanism is not efficient and can take 90 to 120 days to achieve. Start-up operation can be accelerated by enhancing the rate of convective heat transfer to the formation by techniques such as bullheading and cold/hot dilation.

At Nexen's Long Lake in-situ SAGD project, the use of higher injection pressures to enhance start-up is limited by the presence of high water saturation zones within the bitumen pay zone ("lean zones"), an adjacent Quaternary-age fresh water-bearing channel, and shallow formation depth. In order to overcome these constraints, an approach using solvent injection in a warm system with enhanced injectivity was successfully designed and implemented. In this approach, the solvent was injected in a high bitumen saturation system after circulating the well for about 70 days. Then, the solvent was chased with hot water into the formation to deliver the solvent deeper into the formation and enhance the rate of solvent-bitumen mixing during the soaking time.

This paper reviews the design criteria, well selection process, and implementation of warm solvent injection in the conducted pilot in the start-up phase of Pad 13 at Long Lake. It also compares production responses of solvent-treated and control wells with comparable reservoir properties within the same pad to evaluate the performance of the designed pilot. Review of the production data shows that the solvent-treated well pair has outperformed all the other well pairs of the pad with no apparent conformance issues. This well had a quick ramp-up which is considerably faster than the average ramp up time at the Long Lake project. The collected data suggests that applying solvent-assisted start-up in systems that have enhanced mobility by pre-circulation of steam can shorten the circulation time and accelerate the ramp-up phase after SAGD conversion.
A Systematic Approach for Inflow Control Devices Testing in Mackay River SAGD Wells
Authors: Becerra O.. , Kearl B.. , Sanwoolu A..
Published: June 2014

Inflow control devices (ICDs) have been extensively used in horizontal wells for conventional oil and gas production in order to prevent early water break through or gas coning. The benefits associated with this technology have been studied with reservoir simulation and validated with field experience. Some of the benefits associated with ICDs that have been described in the literature are: easier well clean out during start up because the ICDs allow application of higher drawdown to poorly performing sections of the reservoir, higher recovery factor caused by delayed water break through or gas coning, uniform production contribution of the horizontal section, and better sand control by limiting the fluid rate per joint.

In theory, similar benefits can be achieved using ICDs in SAGD applications. In this case steam break through instead of gas coning could be prevented. If live steam production is mechanically controlled by the ICDs, bitumen from the colder sections of the production well can be produced by applying a higher drawdown. In this way the total bitumen production should be increased while steam oil ratio (SOR) is reduced. Nevertheless, the available drawdown between SAGD well pairs is very limited and the conventional design approach consisting of uniform flow along the horizontal section is not applicable.

To design an ICD completion trial at the MacKay River SAGD Project, Brion Energy has conducted studies involving theoretical analysis, segmented well simulation, technology evaluation, and equipment selection. The results of these studies indicate that higher cumulative production with lower SOR can be achieved when the ICDs are installed in bitumen production wells where the reservoir exhibits significant heterogeneities. However, the hot spots in the well have to be produced at zero wellbore sub-cool in order to generate a differential pressure capable of bringing colder sections of the well into production. The study also suggests that a further reduction in SOR can be achieved when the ICDs are also installed in the steam injection wells.
Phase Behaviour and Viscosity Reduction of CO2-Heavy Oil Systems at High Pressures and Elevated Temperatures
Authors: Li Xiaoli , Yang Daoyong , Fan Zhaoqi
Published: June 2014

Techniques have been developed to experimentally and theoretically determine phase behaviour and viscosity reduction of CO2-heavy oil systems at high pressures and elevated temperatures. Experimentally, vapour-liquid phase boundaries (i.e., saturation pressure lines) and the swelling factors are measured by conducting PVT tests at pressures up to 11094.0 kPa and temperatures up to 362.75 K, respectively. The viscosity of CO2-saturated heavy oil is measured at 319.15 K. Theoretically, the heavy oil sample is respectively characterized as a single- and multi-pseudocomponent(s). An exponential distribution function is used to split the plus fraction of heavy oil up to C105+, while a logarithm-type lumping method is used to group the single carbon numbers (SCNs) into multiple pseudocomponents. Then, the Peng-Robinson equation of state (PR EOS) coupled with the modified alpha function is applied to quantify the phase and volumetric behaviour of the CO2-heavy oil systems. The binary interaction parameters (BIPs) for CO2-pseudocomponent(s) pair are tuned to match the measured saturation pressures. Compared with the characterization scheme of treating heavy oil as a single pseudocomponent, the absolute average relative deviation (AARD) for the predicted saturation pressures can be improved from 5.27% to 4.56% by characterizing the heavy oil as six pseudocomponents. With the optimum BIPs, the swelling factors are predicted by the PR EOS with and without the volume translation technique, respectively. It is found that the introduction of the volume shift to each (pseudo)component in the PR EOS is able to provide more accurate prediction in both characterization schemes with AARD of 1.88% (oil as a single pseudocomponent) and 1.39% (oil as six pseudocomponents), respectively.
Investigation of the Physical and Chemical Genesis of Deep Tar-Mat Oil and Its Recovery Potential under Different Temperatures
Authors: Almansour Abdullah , Al-Bazzaz Waleed , Saraswathy Geetha , Sun Yongpeng , Bai Baojun , Flori Ralph
Published: June 2014

Deep tar-mat layers, which occur between the aquifer column and the reservoir-oil column, contain substantial quantities of extremely heavy oil and are found in various parts of the world, most prominently in Middle Eastern nations such as Saudi Arabia, Qatar, south Iraq, and Kuwait. Tar mats are thick layers with oil gravity of less than 10 °API; they isolate conventional oil reservoirs from their aquifers either partially or completely, causing numerous problems when applying oil recovery technology. However, in this study, tar mats are considered as a potential source from which to extract difficult oil. Researchers have attempted to experimentally evaluate the effect of toluene, hot water, and surfactant solution extractions on several carbonate tar-mat rock samples at several different temperatures (25°C, 135°C, 225°C and 315°C). In the study presented in this paper, samples were selected from a tar-mat carbonate reservoir in Kuwait. The physical and chemical geneses of tar-mat oil were analyzed utilizing several experimental geochemical techniques, such as rock evaluation pyrolysis, liquid extracts for Saturates, Aromatics, Resins, and Asphaltenes (SARA analysis), and elemental fingerprinting of Carbon, Hydrogen, Nitrogen, Sulfur, and Oxygen (CHNSO). These geochemical techniques were integrated in order to quantitatively evaluate the tar-mat recovery patterns of the carbonate reservoir at different temperatures. The results showed that the oil recovery significantly increased as the temperature increased. A comparison of all three methods indicates that for light and heavy tar mats, toluene produced the highest oil recovery at all temperatures tested, reaching as high as 47.1% at 315 °C. The surfactant treatment yielded less oil recovery than toluene, which reached as high as 7.5% at 315 °C. The temperature had a significant effect on light tar-mat oil recovery when using water methods; the oil recovery reached as high as 6.2% when using water at 315 °C. However, high-temperature water had little effect on extremely heavy tar mats. The paper provides a systematic method by which to quantitatively characterize tar-mat crudes in carbonate reservoirs.
Correlation of Permeability and Volume of Shale in Oil Sands: Improving Predictability in Low Permeability Zones of the McMurray Formation, Alberta, Canada
Authors: Dabek Les , Shad Saeed , Abdinia Ali Dalir , Knepp Rex
Published: June 2014

The Lower Cretaceous McMurray Formation of Alberta, Canada, contains vast quantities of bitumen. Oil sands hosting this bitumen were deposited and reworked by tidal and fluvial currents, resulting in heterogeneous sediment distributions comprising cross-stratified and massive sands, breccias, and low permeability sand- to mud-dominated inclined heterolithic stratification (IHS). Conventional reservoir characterization workflows suggest that reservoir permeability correlates most closely to volume of shale (vShale). One aspect of such workflows is derivation of an empirical correlation between permeability obtained from core analyses and calculated vSh from wireline logs. While there may be numerous direct measurements from core samples, uncertainty in oil sands reservoir permeability is known to result from preferential sampling of clean sands versus muddy IHS and from scale differences between core sample and well log resolution. This uncertainty is particularly significant in facies with permeability < 500 millidarcy. We integrated multi-scale exploration data from a producing McMurray Formation reservoir to demonstrate the impact of centimeter-scale reservoir architecture on permeability. The study uses high-resolution 3D models of the near-wellbore region to characterize observed variability in percentage, orientation and dimension of mud laminae, breccia clasts and trace fossils. We created multiple realizations to capture the variability in model simulation parameters. High-resolution models of several million cells were upscaled at the resolution of the vSh log using a flow simulation-based numerical method. Upscaling results are estimates of effective directional permeability (kx, ky, kz). The flow-based permeability results better define the interrelationship of permeability and vShale within a reservoir. Our results demonstrate a modeling workflow that provides more precise permeability estimates at wireline log resolution. This workflow has the potential to improve history matching in flow simulations and improvements in well placement and performance forecasting.
Environmental Impact of Bitumen Extraction with Thermal Recovery
Authors: Morrow A. W. , Mukhametshina A.. , Aleksandrov D.. , Hascakir B..
Published: June 2014

The continuous and growing demand for energy and carbon based products requires the extraction of massive bitumen resources. Due to extremely high viscosities of bitumen, the most effective bitumen extraction methods are thermal enhanced oil recovery (EOR) methods such as In-situ Combustion (ISC), Steam Assisted Gravity Drainage (SAGD), Steam Flooding (SF), and Hot Water Injection (HWI) which are known as environmentally unfriendly bitumen extraction methods. In this study, we investigated the environmental impact of in-situ bitumen extraction by ISC, SAGD, SF, and HWI, experimentally. The original oil, water, and rock, produced oil and water, and spent rock samples originated from each recovery method were analyzed through Fourier Transform Infra-Red (FTIR) spectroscopy, Inductive Coupled Plasma – Mass Spectroscopy (ICP-MS), pH, viscosity, and API gravity measurements. The environmental impact was investigated according to the amount and content of produced water and gas samples and the quality of oil to reduce the impact during bitumen refining. The experimental results showed that while with ISC, the least amount of water is produced; the produced water requires more severe treatment due to its high metal and sulfur contents, and low pH level. On the other hand, since the amount of the produced water for SAGD, SF, and HWI is higher, the produced water management poses handling problems. The oil production from ISC results in the greatest recovery with upgraded oil which will reduce the environmental impact for oil processing when compare to SAGD, HWI, and SF. While all processes produced more or less the same amount of gases, SAGD and SF have additional gas production due to steam generation. As conventional resources decline, it is essential to address environmental challenges to produce from these massive oil sand resources. In this study, the environmental impacts of bitumen extraction with thermal EOR were examined extensively.
NCG Co-Injection at Hangingstone Demonstration Project – Case Study and Analysis
Authors: Doan Luong T. , Harschnitz Brian , Shiga Norihiko , Pennacchioli Enzo , Park Bob
Published: June 2014

The application of NCG co-injection into matured SAGD development has been well documented. At several commercial development projects1–3, it has become the standard operating practice to improve the SOR of the patterns and total project.

At the Hangingstone Demonstration Project, JACOS had implemented the first NCG co-injection pilot in 2007 at Phase 1 wells (A-B wells), which was reported by Wang4. Since November 2010, continuous co-injection started at Phases 1 & 2 wells (A-E wells), but was temporarily shut-in in September 2011 due to several interruptions of the gas supply. We used this opportunity to re-establish a base case steam injection scenario only; stable steam injection and reservoir withdrawal took effect for the next 8 months. Co-injection restarted in June 2012 to again improve the thermal efficiency of the Phases 1 & 2 development. As a consequence, two distinctive NCG co-injection periods could be observed. The second and third periods took place between November 2010–September 2011, and between June-December 2012; respectively for the A-E well pairs (Phases 1 & 2).

Our NCG co-injection experience to-date revealed that: 1) Bitumen production is not compromised, 2) The steam oil ratio (SOR) can be reduced, 3) When NCG co-injection ceased, the gas previously in the chamber – observed via temperature observation well – could no longer be detected, 4) Lower emission intensity of CO2 gas from steam generation can be achieved, 5) The steam injected (CWE) was balanced against the water produced, and 6) Allocation of steam to new well(s) or non-thermally matured wells can maximize overall field production.

These positive results led to propose expanding the desired NCG co-injection into Phases 3 & 4 wells (H-Q well pairs), where some of the well pairs had been operating since November 2001 and at different stage of thermal maturity. The design of this NCG co-injection expansion along with field issues associated with implementation will also be discussed.
Oil Drainage Characteristics during the SAGD Process to Explain Observed Field Performance
Authors: Ito Yoshiaki
Published: June 2014

The general concept of the SAGD process is that a steam chamber first expands to the top of the reservoir and thereafter continues to grow by lateral expansion. Consistent with this concept is the expectation that the steam oil ratio (SOR) rises as the SAGD operation matures, driven by expanding contact area and heat losses between the steam chamber and the overburden.

However, analysis of a number of successful SAGD projects, with operating histories of 10 years or more indicates that there is clear evidence that observed performance can deviate significantly from the performance predicted by the above concept. One particularly interesting set of observations shows a declining or unchanged SOR at the mature stage. An examination of this SOR behavior and several other unexpected SAGD performance characteristics detected in the field are presented.

It is proposed that the above field performance characteristics are consistent with the interpretation that the steam chamber does not rise to the top of the reservoir prior to expanding laterally. In these cases oil production is achieved by two different mechanisms: one is expansion of the steam chamber and the other is drainage of oil from the layer above the steam chamber. A simulation method and the results of a number of history matching studies are presented to explain the oil and gas flow in the layer above the steam chamber and its contribution to observed SAGD performance.
Oil Recovery Mechanisms in Bitumen-Bearing Carbonate Rocks
Authors: Bryan J. , Kantzas A.
Published: June 2014

Bitumen-bearing carbonate reservoirs, dominated by the 406 billion barrel resource in the Grosmont formation, will provide billions of barrels of recoverable oil for the Province of Alberta. A small contribution to this development was an extensive series of initial laboratory experiments that were conducted for multiple producers under a variety of conditions. The experiments include measuring oil recovery to varying water and steam processes, both separately and in combination with each other. Displacement procedures included both washing/soaking and direct floods with temperatures ranging up to 260°C. These laboratory tests were conducted over a six year period.

As this research was conducted across several producers independently, a planned statistical design was not addressed through this process. Rather, the experiments are exploratory in nature, examining the primary recovery mechanisms contributing to production performance and ultimate recovery of bitumen in these heterogeneous systems. It has been shown that bitumen can be readily recovered from fractured and connected open porosity that is accessible to steam through a gravity drainage process. Furthermore, carbonates at elevated temperatures become more water wet, and water imbibition can play a significant role in accessing recovery from the oil-bearing rock matrix. The impact of imbibition is significant, and wet steam proves a much more efficient displacing medium than dry steam. The recovery of oil from lab-scale models also shows a significant impact of thermal expansion and gas drive, which can lead to significant oil displacements at early times, particularly in areas where the localized open porosity network is extensive. Bitumen recovery from carbonate systems is achieved through a combination of these processes: thermal expansion, gas drive, gravity drainage of oil out of connected open porosity, and imbibition of water into the rock matrix.
Field Trial Outcomes of a Permanent Magnet Drivetrain for Progressing Cavity Pumps
Authors: Cochran Jamie , Franks Spencer
Published: June 2014

This paper details the findings and outcomes of field trials of a new artificial lift technology.

The technology is a submersible permanent magnet drivetrain for a progressing cavity pump which was tested for cyclic steam stimulation heavy oil applications in the San Joaquin Valley, California. The drivetrain has been designed to provide sufficient torque with high efficiency within a small package, enabling optimum placement within the wellbore.

The effectiveness of steaming and the geothermal temperature variance at the reservoir is investigated using multiple data points over time. The impact of operating the artificial lift system at different speeds is explored, including interpretations of specific downhole events during the trials. Field trial data, from field installations is presented, from which key findings are shown. This paper will present a study into the relationship between progressing cavity pump performance, temperature, oil cut and fluid viscosity.

The effect on the well production and performance with respect to events and activity in surrounding wells was also analysed using surface and downhole data collected during the trials.
Remote Monitoring of SAGD Operations with Satellite based InSAR
Authors: Henschel Michael D. , Shen Luyi , Shipman Todd , Lehrbass Brad , Aubé Guy
Published: June 2014

Surface deformation, measured from space, provides a means to remotely monitor Enhanced Oil Recovery (EOR) activities. Using Interferometric Synthetic Aperture Radar (InSAR) to measure surface deformation allows for a common measuring stick with no access issues. Currently surface deformation is measured using many alternative approaches, some of which are less economical and not feasible at the regional scale when compared to InSAR. Information collected from InSAR could be used to develop an informed planning mechanism.

Space based SAR data from January 2009 to August 2011 was examined over a SAGD site in Alberta, Canada. The data was extracted from the satellite archives and advanced InSAR processing techniques were applied to measure the surface deformation over the site.

The InSAR results show the extreme variability in the ground conditions that are to be expected in the region. The surface deformation was measured using a combination of corner reflectors and infrastructure targets. The highly variable ground conditions make monitoring of subtle deformation signals (2.5 – 5 cm/yr) difficult to measure without the use of installed targets. The challenges of InSAR monitoring without installed targets are addressed to emphasize the importance of on-site ground control points.

Furthermore, the surface changes observed with the InSAR results are related to reservoir changes. Geomechanical simulation is dependent on many rock physics parameters and complex geological frameworks. History matching with InSAR observation provides enhanced prediction and estimation of reservoir growth, which can inform decisions related to reservoir performance and caprock integrity.

This paper is a result of a collaboration between the Alberta Energy Regulator, MDA Geospatial Services Inc. (MDA), and the Canadian Space Agency (CSA) to examine the requirements for rapid-turnaround measurement of ground deformation over enhanced oil recovery sites in the Alberta Oil Sands. Funding for this effort was partially provided by the CSA.