bluuebunny/crossref_metadata_2025 huggingface dataset:
Rasio Spermatozoa X:Y dan Kualitas Sperma pada Kambing Kacang dan Peranakan Ettawa
Authors: Bintara S
Published: February 2017

The objective of the study was to know the difference of X:Y spermatozoa ratio and sperm quality of Kacang and Ettawa-crossed breed goats. It was conducted at Laboratory of Animal Physiology and Reproduction, Faculty of Animal Science Universitas Gadjah Mada for three months, starting December 2009 to February 2010. Materials of the study were sperm collected from six two-year Ettawa-crossed breed goats weighing 31.5±2.2 kg and from six two-year Kacang goats weighing 18.0±2.1 kg. The sperm was collected using artificial vagina with frequency of twice a week for each goat and it was repeated eight times. The quality and quantity of the sperm was immediately evaluated by its volume, concentration, motility, viability and abnormality. To determine the ratio of X:Y spermatozoa, smear preparation was made and spermatozoa head was then measured using Scion Image software. The results of the measurement were used for identification of X or Y spermatozoa. Spermatozoa having bigger head than the average were identified as X and those having smaller head as Y. The result showed that the ratio of X:Y spermatozoa of Ettawa-crossed breed goats (50.6±1.8:49.4±1.8 %) was not significantly difference with that of Kacang goats
(49.7±1,7:50.3±1.7 %). Sperm volume of Ettawa-crossed breed goats (1.00±0.2 ml) was higher than that of Kacang goats (0.62±0.2 ml). Sperm concentration of Ettawa-crossed breed goats (2,865±431 million/ml) was not significantly difference compared to that of Kacang goats (2,840±383 million/ml). Spermatozoa motility of Ettawa-crossed breed goats (66.7±9.8 %) was higher (P<0.05) than that of Kacang goats (50.0±7.1 %). Spermatozoa viability of Ettawa-crossed breed goats (80.0±7.1 %) was higher (P<0.05) than that of
Kacang goats (67.5±9.4 %). Spermatozoa abnormality of Ettawa-crossed breed goats (8.2±3.3 %) was not significantly difference compared to that of Kacang goats (8.6±2.4 %). The study was concluded that the breeds of Ettawa-crossed breed and Kacang goats have indifferent ratio of X:Y spermatozoa, while the sperm volume, motility and viability of Ettawacrossed breed goats was better than that of Kacang goats.

Key words: XY spermatozoa, quality and quantity, Ettawa-crossed breed, Kacang.
Profitabilitas Usahatani Sapi Perah Rakyat di Kabupaten Sleman
Authors: Emawati Shanti
Published: February 2017

The research was conducted to determine the profitability of investment on dairy
cattle farm in Sleman District. Research was done from Juni to July 2009, located in Sleman District. Survey method was done to collect primary data at the farm level and secondary data from related institution and interview with questioner. Purposive sampling was applied to select farmers’ respondent. Criteria used to analyze profitability of investment were consisted of Benefit Cost Ratio (BCR), Net Present Value (NPV), Internal Rate of Return (IRR) and Payback Period (PPC). The result of analysis based on 5 years investment and 12% annual discount factor showed that the value of NPV = Rp. 15,710,080.00; BCR = 2.10; IRR = 41.79% and PPC = 2.6 years. Dairy cattle farm in Sleman District was financially feasible.

Key words: dairy cattle, farm, investment, profitability
Insulated Coiled Tubing as a Tool for a Thermal EOR Process Through Non-thermal Well
Authors: Damour J. , Johannson D.
Published: February 2017

A thermally insulated coiled tubing is permanently inserted in a horizontal heavy oil producer well and used to circulate hot oil (or water) in the well to heat by conduction the vicinity of the liner, where the drawdown is the most important. This process can be used in non-thermal wells and improves heavy oil field production with a limited quantity of energy. This paper presents the typical completion applied for this EOR process, the well integrity concerns due to high temperature and the calculated oil production increase that is confirmed by field application.

The insulated coiled tubing is inserted into the horizontal well up to the well-toe. The production tubing is installed parallel to the insulated coiled tubing. The process is pumping hot oil at 230°C (or water) through the insulated coiled tubing. The heated oil is circulating from the well-toe back to the well-heel in the liner and heat the reservoir by conduction. This energy delivered to the reservoir will reduce the oil viscosity within a few meters from the liner and allow lower pressure drop.

A transient thermal model has been developed to model this EOR process. The equations on which the model has been built are Darcy's law, the continuity of the flow and the energy balance. Some assumptions were taken to simplify the model such as constant reservoir properties over space and time.

The model provides the temperature along the liner with max temperature at the toe and min temperature at the heel as well as the radial temperature in the reservoir. It models also the extra oil production allowed by the process. The temperature involved on the critical parts of the completion remain low and allow to apply this EOR on non-thermal wells. The field monitoring (temperature and net oil production) of the first pilots in Canada have confirmed the model results. The energy consumption requested is approx. 400kW, ten to twenty times lower than typical steam injection process. This process is not a competitor for steam injection but a good way to improve the production of heavy oil well with low CAPEX and low OPEX for specific fields where steam injection is not efficient like fields with thin reservoir.

In this tough period for the oil industry, this technology can be applied on existing producer wells without drilling injector wells. The combination of this process with waterflooding is a win-win association. Waterflooding brings the driven mechanism to the reservoir and the thermal process allows better oil flow at the well.
Performance Prediction of Solvent Enhanced Steam Flooding for Recovery of Thin Heavy Oil Reservoirs
Authors: Huang Shijun , Liu Hao , Xue Yongchao , Xiao Peng , Xiong Hao
Published: February 2017

More than half of heavy oil reservoirs in Western Canada are less than 5m thick and SAGD is generally not thought to be economically viable for such kind of reservoirs due to lack of Potential Energy of Gravity and significant heat losses to the overburden. Solvent enhanced steam flooding (SESF), a kind of enhanced steam flooding by co-injecting solvent with steam, has shown to be promising in enhancing oil rates in thin reservoirs. In this paper, a semi-analytical model is established for predicting production performance of SESF.

The model is mainly built based on Energy Conservation and Fick's Law to predict the steam front position as well as the solvent concentration profile in the reservoir. Besides, the blocking effects of steam condensate on solvent diffusion is modeled by introducing the oil-water two phase flow theory. Then, the model is divided into three parts corresponding to the three production stages of SESF, and they are semi-analytically solved successively. The proposed model is validated by comparing calculated oil production rate with the results of a numerical simulation method. The results indicate that the enhancement of oil production rate mainly happened in the early stage of the process which is achieved by the combining effects of heat and convection-enhanced mixing of solvent and heavy oil. On the basis of a sensitivity analysis for performance of SESF, it is realized that the operating thickness and solubility of a solvent are proportional to steam oil ratio reduction of SESF compared to conventional steam flooding. Besides, a relatively lower injection rate and a longer well spacing may result in higher thermal efficiency increment due to longer contacting time of solvent with crude oil.

Piloting SESF in a field has many challenges, especially when considering its main economic factors: production increase and solvent cost. Therefore, it is anticipated that considering the dynamic mass transfer and blocking effect of accumulated condensate on solvent diffusion in SESF process, which are important mechanisms of SESF with inadequate understanding in literatures, the newly developed model will help to better predict and design the future SESF heavy oil recovery projects in thin pay zones.
An Investigation into Temperature Distribution and Heat Loss Rate within the Steam Chamber in Expanding-Solvent SAGD Process
Authors: Liu Hao , Cheng Linsong , Li Chunlan , Xiong Hao , Xiao Peng
Published: February 2017

In order to save energy and to be more environmentally friendly, Expanding-Solvent SAGD (ES-SAGD) is proposed by adding solvents into the injection vapor. However, much heat may still be wasted due to early steam condensation, which is associated with heat transfer and phase behavior within the steam chamber during ES-SAGD process. The objectives of this paper are to study temperature distribution within the steam chamber and to evaluate the overall heat loss rate of ES-SAGD by using a semi-analytical model.

In the mathematical model, temperature and mass profiles within the chamber are implicitly represented rather than explicitly treated as beyond the edge of the chamber. By considering early steam condensation and phase change within the chamber, the model dynamically couples heat transfer equation and mass transfer equation. This approach allows us to clearly observe the heat loss rate within the chamber as well as to the overburden. The model is solved iteratively after the steam velocity at the chamber edge is determined by introducing theory of steam front stability. Finally, the proposed model is validated by comparing calculated temperature profile with the numerical simulation results.

The results of the analytical study reveal that, for solvents with smaller molecular mass, the temperature starts dropping deeper from chamber edge to the injection end, and the temperature gap between the two ends is larger than that of heavier solvents. Based on the calculated temperature profiles, it is considered that heavier solvents may not improve thermal efficiency, while lighter solvents can help to reduce heat loss rate to the overburden especially in the late stage of ES-SAGD. Moreover, although lighter solvents are always used to relieve the heat losses to the overburden, the heat wasted inside the steam chamber is severer than that of heavier solvents. Therefore, considering the total heat losses to the overburden and inside the steam chamber, the steam/oil ratio (SOR) of ES-SAGD in some ultra-thick reservoirs may be unfavorable even compared with that of SAGD.

On the basis of analysis for heat loss rate to the overburden and inside the chamber, several guidelines are presented to select solvent for ES-SAGD process. The proposed guidelines will help to better predict and design the future ES-SAGD heavy oil recovery projects.
Pore Network and Morphological Characterization of Pore-Level Structures
Authors: Mohammadmoradi Peyman , Bashtani Farzad , Goudarzi Banafsheh , Taheri Saeed , Kantzas Apostolos
Published: February 2017

Due to the computational simplicity and time efficiency, pore network and morphological techniques are two practical approaches for characterization of pore-scale microstructures. The methods are quasi-static and exploit pore space spatial statistics to simulate pore invasions. Here, both procedures are evaluated applying the workflows to pore-level micro-scale subdomains of Sandstone, Carbonate and Shale formations. A statistical approach is also utilized to improve the accuracy of Shale characterization by spatial restoration of fragmentary parts of organic matter. Post-processing results include relative permeability and capillary pressure curves, absolute permeability, formation factor, and thermal connectivity. The results appear to suggest that the accuracy of pore network modeling in the characterization of subdomains of micro-CT images is compromised by the presence of limited number of network elements, ignoring the resistance of pore elements, multi-scale structures, and tight/weak connections represented by an inadequate number of voxels. Pore network extraction negatively affects the accuracy of petrophysical predictions and ignores solid matrix and its thermal and electrical properties. The pore morphological approach accurately reproduces the fluid occupancies, efficiently deals with a variety of rock configurations and resolutions, and preserves connectivity and details of original images having more geometrical features than the pore network modeling. However, it predicts limited step-wised data points and realizations sourcing from its voxel-based nature. In addition, direct simulations confirm that stochastic conditional reconstruction of organic matter inside shale sub-volumes remarkably boosts the pore space connectivity and improves the accuracy of predictions.
Overcome Viscous Fingering Effect in Heavy Oil Reservoirs by an Optimized Smart Water Injection Scheme
Authors: Kadeethum T. , Sarma H. K. , Maini B. B.
Published: February 2017

Viscous fingering is a major obstacle to successful waterflooding in heavy oil reservoirs, as it results in water breakthrough and an undeveloped oil bank. To overcome viscous fingering, the composition of injected fluid can be tailored to a production scheme which optimally enhances oil recovery. Smart water can improve oil recovery through wettability alteration. However, wettability alteration also leads change in mobility ratio, which depending on value, may have either a negative or positive impact on oil recovery and water production and must therefore be carefully controlled.

In this study, smart waterflooding outperforms conventional waterflooding regarding oil recovery, with incremental recovery reaching as high as five percent. Moreover, smart waterflooding also significantly decelerates the water cut (WCUT) trend by subduing the effect of viscous fingering and decreasing the water relative permeability. Our results show that reducing a salinity of the injected fluid allows mineral dissolution reactions to raise effective permeability compared to that achieved by conventional waterflooding. Injection and production pressure affect mineral dissolution/precipitation and, consequently, effective porosity and permeability. Numerical simulation is used to analyze the potential of smart waterflooding as an enhanced oil recovery method in heavy oil reservoirs.
Sand Transport Modeling in Heavy Oil Gathering Network in Orinoco Oil Belt, Venezuela
Authors: Mendoza L. , Marin M. , Nascimento C. M. , Peraza R.
Published: February 2017

It is estimated that 70% of the world's oil and gas reserves are contained in reservoirs where sand production is or will become, a problem during the life of the field (Chen et al., 2010). Consequently, an effective sand management strategy may be critical to assure hydrocarbon production.

This study presents some results of a developed sand prediction model that has been used in Venezuela to understand sand transport characteristics in heavy oil and to estimate suspension and deposit critical velocities. In addition, results are presented of a sensitivity analysis of particle diameter and water cut carried out using a dynamic multiphase flow simulator to determine the accumulated solids content in some pipelines that helped to develop adequate cleanup procedures.

Pressure/volume/temperature (PVT) analyses were initially conducted in order to to reproduce the field characteristics of the produced fluid, including diluted fluid. Sensitivity studies were done to evaluate the effects of some parameters, such as grain size, flow rate, and water cut, to determine how they affect critical transport velocities. From these studies, the volume of particles deposited and the thicknesses of these deposits were determined, which helped the operator to define appropriate pigging program to remove sediments and to estimate the effect on the production system without an appropriate cleanup activity.

The initial result shows that the network gathering system operates below deposition critical velocity, however, a stationary sand bed is growing in pipelines near the wells.

In addition, the parametric studies revealed that when the particle sizes increase, the critical velocities increase. Besides that, critical velocity shows different behavior with water cut. Critical velocity increases when the water cut goes from 0% to 5%, but if this maximum value is overcome, the critical velocities decrease. Field data indicated that the amount of material received at the end of the system (CPF) during 500 days is 1600 tons of sand, but the maximum operation allowable pressure is reached 290 days after starting up the oil production. Dynamic flow simulations indicated that it is necessary to start the cleaning operation between 150 and 290 days after the start of production, depending on the available pressure to push the pig.

This paper summarizes the novel contribution of using dynamic flow simulations for sand prediction and a control model in one of the growing joint venture companies in FAJA PetroIndependencia in Venezuela.

Prediction of critical flow rate to prevent sand settling is important for flowlines that are in the design stage. This paper offers a valid approach to extend the predicted sand critical velocities to other fields in FAJA with similar crude conditions to aid in pipeline design.
A New Mathematical Model of Solvent-SAGD Process - Importance of Heat and Mass Transfer
Authors: Zargar Zeinab , Ali S. M.
Published: February 2017

The current in situ exploitation of oil sands in Alberta employs steam-based recovery methods, which are energy-intensive. A few companies are adding solvent to steam aiming to reduce steam requirements. The mechanism of oil recovery by steam with added solvent is not clear. Over the years, on several occasions- as at the present time- the oil industry has resorted to the use of solvents with steam in thermal recovery operations. The past trials with solvent were short-lived in view of the cost of solvents as well as the lack of success. Given the controversy regarding the use of solvents with steam, this work is intended to explain whether solvent injection with steam increases oil recovery or not.

In this work, a new analytical model is developed for describing the solvent-SAGD performance based on the combination of an overall solvent mass balance, heat balance and volumetric oil displacement and Darcy's oil rate using a mixture viscosity model as a function of temperature and solvent concentration ahead of front which satisfy the equilibrium in the system.

The objectives of this work are to predict: vapour-steam chamber growth, oil production rate, solvent production rate, solvent loss (or solvent retention) rate, and the effect of solvent type and concentration on the solvent-SAGD process. The results show that the rate of solvent retention increases over time, while the rate of solvent and bitumen production decreases.

The efficiency of this process is evaluated using cumulative steam-oil and solvent-oil ratio, which permits a comparison of the efficiency of SAGD and solvent-SAGD processes for different solvents. On the whole, the results of this approach give a better understanding of the mechanism of oil production during the solvent-SAGD process by interconnecting vapour chamber conditions and the conditions of heated and diluted oil ahead of the interface.
Water-Soluble Solvent as an Additive to Steam for Improved SAGD
Authors: Sheng Kai , Okuno Ryosuke , Wang Mingyuan
Published: February 2017

Coinjection of solvent with steam results in lower chamber-edge temperatures than those in steam-assisted gravity drainage (SAGD), which enable to decrease heat losses to the overlying formation rocks. However, use of highly volatile solvents, such as propane, can yield significantly slow bitumen production due to low chamber-edge temperatures. The objective of this research is to investigate the potential of water-soluble solvent as an additive to steam for reducing steam-oil ratio (SOR) while keeping SAGD-like rates of bitumen production.

The chamber-edge temperature for a given overall composition and operating pressure is defined as the temperature at which the vapor phase completely condenses with decreasing temperature. Thermodynamic predictions show that the chamber-edge temperature so defined will increase substantially if the solvent can partition into the aqueous phase at chamber-edge conditions. This is confirmedin numerical reservoir simulation for coinjection of steam with dimethyl ether (DME), as a water-soluble solvent, for Athabasca bitumen. In simulation case studies, coinjection of steam with DME (DME-SAGD) is compared with SAGD and coinjection of steam with C4 (C4-SAGD), in terms of SOR, bitumen production, local displacement efficiency, and solvent recovery. The steam-injection pressure is 35 bars for all cases, and 2 mol% of solvent is coinjected in solvent-SAGD simulations until the steam chamber reaches the side boundary of a 2-D homogeneous reservoir model.

DME is more volatile and less soluble in bitumen than C4 at their corresponding chamber-edge conditions. However, results show that DME-SAGD results in 35% lower SOR than SAGD while being able to increase bitumen-production rates of SAGD. Analysis of simulation results indicates that the solubility of DME in water not only makes the chamber-edge temperature higher than that of C4-SAGD, but also yields15% higher solvent-recovery factor than C4-SAGD. The main reason for the latter observation is that a much smaller fraction of the injected solvent is present in the vapor phase in DME-SAGD than in C4-SAGD. Also, DME dissolves in both water and bitumen, which results in the aqueous and oleic phases of nearly-equal density within the gravity-drainage zone near the edge of a steam chamber. This is the neutral regime of oil-water two-phase flow along the chamber edge between the two extreme cases: SAGD and C4-SAGD. Unlike in C4-SAGD, the reduced gravity segregation in DME-SAGD is expected to facilitate the mixing of condensed solvent with bitumen near the edge of a steam chamber.
An AI-Based Workflow for Estimating Shale Barrier Configurations from SAGD Production Histories
Authors: Zheng Jingwen , Leung Juliana Y. , Sawatzky Ronald P. , Alvarez Jose M.
Published: February 2017

An artificial intelligence (AI) based workflow is being deployed to develop and test procedures for estimating shale barrier configurations from SAGD production profiles. The data employed in this project is derived from a set of synthetic SAGD reservoir simulations based on petrophysical properties and operational constraints representative of Athabasca oil sands reservoirs.

Initially, a two-dimensional reservoir simulation model is being employed. The underlying model is homogeneous. Its petrophysical properties, such as the porosity, permeability, initial oil saturation and net pay thickness, have been taken from average values for several pads in Suncor's Firebag project. Reservoir heterogeneities are simulated by superimposing sets of idealized shale barrier configurations on the homogeneous model. The location and geometry of each shale barrier is parameterized by a unique set of indices. The resulting heterogeneous model is subjected to flow simulation to simulate SAGD production.

Next, a two-step workflow is followed: (1) a network model based on AI tools is constructed to match the output of the reservoir simulation (shale indices are inputs, while production rate and the steam-oil ratio are outputs) for a known training set of shale barrier configurations; (2) for a new SAGD production history generated via reservoir simulation with a shale barrier configuration that is unknown to the AI model generated in step 1, an optimization scheme based on a genetic algorithm approach is adopted to perturb the shale indices until the difference between the target production history and the production history predicted from the AI model is minimized.

A number of cases have been tested. The results show a good agreement between the shale barrier configurations predicted by the AI model with the configurations used to generate production histories in the reservoir simulation model (i.e., the "true" model). Thus, this optimization workflow offers potential to become an alternative tool for indirect inference of the uncertain distribution of shale barriers in SAGD reservoirs from data capturing field performance.

This works highlights the potential of an AI-based workflow to infer the presence and distribution of heterogeneous shale barriers from field SAGD production time-series data. It presents an innovative parameterization scheme suitable for representing heterogeneous characteristics of shale barriers. If this approach proves to be successful, it could allow the distribution of shale barriers to be inferred together with the impact of these barriers on SAGD performance. This would provide a basis for developing operating strategies to reduce the impact of the barriers.
2D Transient Simulation of Conjugate Natural Convection and Radiation within Thermal Wellbore Annuli
Authors: Lu Xueying , Xiong Wanqiang , Chen Zhangxin
Published: February 2017

In the petroleum industry, accurately estimating wellbore heat loss in thermal recovery processes remains a critical problem. One difficulty lies in simulating heat transfer and fluid dynamics within wellbore annuli. A literature survey shows that the state-of-the-art thermal wellbore simulators use empirical correlations to calculate the heat loss through wellbore annuli. As more sophisticated wells have been drilled, there is a growing need for a more detailed wellbore annulus heat transfer model. In this study, a 2D transient mathematical model is proposed for the conjugate natural convection and radiation within wellbore annuli. The governing equations consist of a continuity equation, a vorticity transfer equation, an energy transport equation and a radiative transfer equation (RTE). A finite volume approach with a second-order upwinding scheme is implemented for discretization. Newton-Raphson iterations are deployed for linearization. The algorithm is validated by consistence in simulation results compared with benchmark numerical solutions with the Rayleigh number up to 107. Parameters such as an aspect ratio, a radius ratio and a conduction-to-radiation coefficient are examined. A case study on vacuum insulated tubing heat transfer using Marlin Well A-6 data demonstrates the merits of the developed program by the consistence of simulation results compared with field measurements.
The Phase Behavior of Heavy Oil and Propane Mixtures
Authors: Mancilla-Polanco A. , Schoeggl F. F. , Johnston K. , Richardson W. D. , Yarranton H. W. , Taylor S. D.
Published: February 2017

The phase behavior of heavy oil and propane mixtures was mapped from temperatures ranging from 20 and 180°C and pressures up to 10 MPa. Both vapour-liquid (VL) and liquid-liquid (LL) regions were observed. Saturation pressures (VL boundary) were collected in a Jefri 100 cm3 PVT cell and blind cell apparatus. The propane content at which a propane-rich light phase and a heavy pitch phase formed (LL boundary) were visually determined with a high pressure microscope while titrating propane into the bitumen. High pressure and high temperature yield data were measured using a blind cell apparatus. Here, yield is defined as the mass of the indicated component(s) in the heavy pitch phase divided by the mass of bitumen in the feed. A procedure was developed and used to measure pitch-rich and propane-rich phase compositions in a PVT cell.

Pressure-temperature and pressure-composition phase diagrams were constructed from the saturation pressure and heavy pitch phase onset data. High pressure micrographs demonstrated that, at lower temperatures and propane contents, the heavy pitch phase appeared as glassy particles while at higher yields and temperatures it appeared as liquid phase. Propane-free pitch yields as high as 70 wt% of the bitumen were observed. The propane contents of the pitch phase at 50°C and 2 MPa, 50°C and 5 MPa, and 130°C and 10 MPa (all for a feed of 50 wt% propane) were 22 ±0.4 wt%, 26 ±0.4 wt% and 2 ±1 wt%, respectively.

The ability of a cubic equation of state to model the data was explored. The model with temperature dependent binary interaction parameters (BIP) matched the saturation pressures and the LL boundaries at one pressure. However, the model could not match the effect of pressure on the LL boundary. The model also underpredicted yields at high dilution and could not match the LL phase compositions.
Successful 1st Eocene Carbonate Reservoir Steamflood Pilot Mitigates Key Technical Uncertainties for Full Field Development of Wafra Field, PZ Kingdom of Saudi Arabia & Kuwait: Part 2 Simulation Model Validation
Authors: Kumar Raushan , Brown Joel , Lolley Chris , Barge David , Bartlema Ruurd
Published: February 2017

This paper describes the key learnings from detailed data analysis and the application of a probabilistic workflow to achieve a validated dynamic simulation model of the large scale pilot (LSP) that was successfully completed in the 1st Eocene reservoir in the Wafra field, PZ. The development of the validated dynamic simulation model was a key success measure identified for the pilot to assist in the broader Wafra full field steamflood development decision making process.

The pilot consisted of sixteen 2.5 acre inverted 5 spot patterns (16 injectors and 25 producers) with associated steamflood and production facilities. In the execution of this work, detailed analysis of production, pressure, temperature, oil viscosity and geochemical data was conducted to develop key insights into the pilot behavior.

A 1st Eocene LSP steamflood model was successfully validated with production and injection data through the primary and steamflood periods. The validation method took into account uncertainties in static and dynamic properties. A probabilistic methodology using design of experiments on uncertainty parameters, combined with error-filters on multiple responses of rates, pressure and temperature was used in the study. The confidence in the final validated model was high with excellent agreement achieved between pilot and model data. The validated model also captured regional behaviors observed in the production data analysis. The validated model captured both pre-steam and post-steam behavior in the pilot. The successful execution of this work has resulted in an estimate of carbonate steamflood recovery possible in the 1st Eocene reservoir in Wafra.
Successful 1st Eocene Carbonate Reservoir Steamflood Pilot Mitigates Key Technical Uncertainties for Full Field Development of Wafra Field, PZ Kingdom of Saudi Arabia & Kuwait: Part 1 Steamflood Results
Authors: Brown Joel , Lwin Al , Barge David , Al-Mutairi Ghanim , Al-Gamdi Saleh , Kumar Raushan , Littlefield Brian
Published: February 2017

A large-scale steamflood pilot test has been successfully completed in the 1st Eocene reservoir. The 1st Eocene is a multi-billion-barrel heavy oil carbonate reservoir in the Wafra field, located in the Partitioned Zone (PZ) between the Kingdom of Saudi Arabia and Kuwait. The pilot was the first multi-pattern steamflood in a carbonate reservoir in the Middle East.

The pilot consisted of sixteen 2.5-acre inverted 5-spot patterns with associated steamflood and production facilities. The primary objective of the pilot was to identify and mitigate technical and economic risks and uncertainties in carbonate steamflooding to assist in the broader Wafra Steamflood full-field development decisions. In the execution of the pilot, performance measures were developed to assess steamflood success in a carbonate reservoir. These success measures included key metrics that were prerequisites for the full field steamflood development of the field. In September 2013, the pilot reached a key milestone and success measure when steam zone development was assessed in the pilot area. Another key success measure was the successful validation of pilot results using thermal reservoir simulation.

The 1st Eocene reservoir in Wafra field, PZ is a challenging asset, with the potential for large reserve additions, in which steamflood technology and learnings from conventional steamflood fields are being leveraged. In this paper, we will share the steamflood results achieved in the pilot with focus on the accomplishment measures set for the project and the progress made in identifying and mitigating key uncertainties in carbonate steamflooding.
Applying Ball-Activated Completion Technology to SAGD Tubing Deployed Outflow Control Devices to Eliminate Well Intervention
Authors: Webb P. D. , Gauthier J. , Skeates C.
Published: February 2017

Outflow Control Devices (OCDs) are commonly used in SAGD horizontal injection wells to enhance steam distribution in the well and facilitate uniform heating of the reservoir. Multiple devices are positioned in the tubing string across the horizontal portion of the well to create the desired steam distribution. Most OCD designs incorporate a sliding sleeve which is run in the closed position to allow steam to be circulated through the well. Circulation continues until sufficient injectivity can be achieved, allowing for bullhead steam injection. Post circulation, the sliding sleeves require coiled-tubing intervention to shift the sleeves open, activating the OCD. The subject method applies existing technology from horizontal multistage ball-activated completions to tubing deployed SAGD OCDs to eliminate the requirements for the initial coiled-tubing well intervention.

The ball-activated OCDs are activated by pumping degradable balls from surface to land in the OCD. Once landed, the tubing is pressured up to the predetermined shifting pressure, the sliding sleeve shifts open, and the ball disengages from the seat and continues to the end of the tubing string. This process is repeated with progressively larger balls for all the installed OCDs.

Product qualification has been completed to ensure SAGD service requirements are achieved. This includes ball degradation tests in boiler feed water, flow loop ball shift testing at ambient and elevated temperature, and mechanical tool shifting tests. The results of this testing are shared.

Through the elimination of the coiled-tubing intervention, significant operational efficiencies and cost savings are anticipated. In addition, the expected efficiency gain will minimize well down-time, resulting in less reservoir cooling and impact to production.
Effects of Concentration-Dependent Diffusion on Mass Transfer and Frontal Instability in Solvent-Based Processes
Authors: Yuan Qingwang , Zhou Xiang , Zeng Fanhua , Knorr Kelvin D. , Imran Muhammad
Published: February 2017

Mass transfer plays a key role in affecting the efficiency of solvent-based processes in enhanced oil recovery. The mass transfer is usually very slow because of the pure molecular diffusion. However, it can be greatly enhanced by frontal instability when solvent is injected to displace oil. Under unfavorable mobility contrast, the interface between two fluids may become very convoluted as displacements continue. This therefore increases the contact area and leads to more efficient mixing. It is necessary to accurately simulate the detailed frontal instability and its propagation with time in order to investigate its effect on the mass transfer.

Most of previous numerical simulations assumed a constant diffusion coefficient (CDC) in solvent-based processes. However, experimental studies on the mixing between two miscible fluids indicated that the diffusion coefficients actually vary with concentration or viscosity. Moreover, some numerical simulations with commercial simulators also showed that using the CDC may result in very high and unrealistic values when matching the oil production rate.

In present study, a concentration-dependent diffusion coefficient (CDDC) is considered in which the diffusion coefficient is exponentially proportional to concentration. Highly accurate nonlinear numerical simulations are conducted to simulate the frontal instability under unfavorable mobility ratio between solvent and oil. The effect of injection rate and mobility contrast on frontal instability and mass transfer is examined, and the breakthrough time for the CDDC case is discussed. For better comparisons, the CDC case is presented to more clearly show the effects of CDDC.
Comparative Study of SAGD and Solvent and Water Assisted Electrical Heating: Effect of Shale Layers
Authors: Ma Mingxu , Rabiei Faradonbeh Moosa , Hassanzadeh Hassan , Harding Thomas G. , Zanon Stefan
Published: February 2017

Bitumen recovery using solvent and water assisted electrical heating has shown promise to be more efficient than the current thermal recovery method of steam assisted gravity drainage (SAGD). Solvent and water assisted downhole electrical heating has potential to eliminate large steam generation plant and water treatment facilities and greatly reduce the capital and operating costs during oil sands development. It is demonstrated that in this process, a hot vapor chamber analogous to that created in SAGD is formed using downhole heaters and injection of a moderate volume of water and liquid solvent as working fluids.

In this work, a kinetic model was integrated into reservoir simulation model to describe aquathermolysis and thermal cracking of bitumen at reservoir conditions. The solubility of gases in both oil and water were included in the simulation. Solvent and water assisted electrical heating was then modeled for oil sand reservoirs with shale layers and the performance was compared with SAGD process. Various distributions of shale layers were introduced through experimental design using different lengths and distances to injector.

Results indicated that production rates by SAGD were greatly affected by shale layers. Production rates were reduced when the steam chamber reached a low-permeability shale layer, especially if the shale layer was wide and close to the injector. However, production rates by solvent and water assisted electrical heating were quite steady even if a vapor chamber met a shale layer. This process led to a box-shaped vapor chamber which was able to grow horizontally and bypass shale layers quickly. In addition, it was found that production rates by SAGD were high in the early stage but declined over time whereas production rates by solvent and water assisted electrical heating were steady and did not change much over the life of the process.
Numerical Prediction of H2S Production in SAGD: Compositional Thermal-Reactive Reservoir Simulations
Authors: Ayache Simon V. , Preux Christophe , Younes Nizar , Michel Pauline , Lamoureux-Var Violaine
Published: February 2017

Nowadays EOR methods such as thermal techniques are widely used to recover the viscous hydrocarbons from heavy oils and bitumen reservoirs. One of the thermal methods is the Steam-Assisted Gravity Drainage (also called SAGD), which consists in injecting steam into the reservoir to melt the viscous oil and allow its mobility. The melted oil falls by gravity to the production well. The injected hot steam, once it reaches the heavy oils/bitumen, induces chemical reactions called aquathermolysis. These reactions generate gases such as hydrogen sulfide (H2S) or carbon dioxide (CO2). The H2S is known to be highly toxic and corrosive. Hence it needs to be given a particular attention when it is produced at the surface. Reservoir models have been built to simulate thermal effects during a SAGD process but only few publications in the literature deal with the aquathermolysis reactions occurring in reservoirs where steam is injected.

This paper focuses on building a reservoir simulation model to forecast the H2S production. The example of the Hangingstone heavy oil field in Canada has been chosen. This simulation model is based on a compositional PVT description for heavy oil/bitumen and on a recently developed sulfur-based compositional kinetic model to describe the aquathermolysis reactions. The description of the heaviest components found in heavy oils/bitumen is made through a SARA decomposition.

The reactive model that describes the aquathermolysis reactions is firstly presented. Then a section of this paper is dedicated to the building of a PVT model for heavy oil. Another chapter presents the 2D heterogeneous reservoir models used for the simulations. Finally the simulations results are presented. A sensitivity analysis has been performed to investigate the effect of the rock conductivity and the pressure/temperature of the injected steam on the H2S production. The different simulations have given consistent results with production data in terms of H2S production at surface. This shows that both the fluid description and the aquathermolysis kinetic model used in the study are relevant for the prediction of H2S production in the context of steam injection.
Measurements of Permeability Change in Inter-Bedded Shale at Elevated Temperatures
Authors: Oldakowski K. , Sawatzky R. P.
Published: February 2017

The geomechanical response of a reservoir to the Steam Assisted Gravity Drainage (SAGD) process involves changes in stress, deformation (strain), and permeability. For example, in many SAGD operations the steam injection pressure is greater than the initial reservoir pressure. As the local pore pressure is elevated by steam injection the effective stress in the reservoir is reduced. This may bring local shear failure and dilation of the reservoir material if the change in effective stress is large enough, particularly where the initial stress environment is anisotropic. In turn, dilation can result in substantial permeability enhancement. A better understanding of the interdependence between stress, deformation and permeability could help in improving the design of SAGD operations to take advantage of the effects of dilation, particularly on vertical permeability barriers such as zones of inter-bedded shale (IBS).

This paper presents the results of experiments investigating changes in the permeability of IBS samples under pressure and temperature conditions similar to those that exist during SAGD operations. The IBS samples used in the tests were cut from cores that had been obtained from a relatively shallow depth (∼ 160 m) at the Dover site in the Athabasca region. The samples consisted predominantly of quartz (∼ 70%), with a clay content of just over 20%. Experiments were performed at both ambient temperature (∼ 22°C) and elevated temperature (∼ 200°C). Elastic properties (Young's modulus, Poisson's ratio) and shear strength parameters (cohesive strength, friction angle) for the IBS samples were also measured at both ambient temperature and elevated temperature.

The experiments were performed in a triaxial cell, under conditions in which the pore pressure and the axial and confining (radial) stress were controlled. The measured increases in permeability caused by a reduction in effective stress were significant at low effective stress. At ambient temperature, the permeability increased by as much as a factor of 15,000 to a level in the range of 1-5 millidarcies (md). At elevated temperature, the permeability increase was even larger, by another order of magnitude, to a level in the range of 10-50 md. The triaxial compression tests indicated that the elastic properties and shear strength of the IBS samples were also sensitive to temperature. The samples became much stiffer (higher Young's modulus) and stronger at elevated temperature.

The study presented here was focused on measurements of permeability change under conditions representative of SAGD in IBS samples obtained from one site, a relatively shallow one. Further tests should be undertaken to investigate permeability change in IBS samples that originate from different sites and different depths, to search for broader trends in the permeability behaviour of IBS under SAGD conditions.
A Practical Approach to the Use and Design of Flow Control Devices in SAGD
Authors: Lastiwka Marty , Bailey Chris , James Bruce , Zhu Da
Published: February 2017

Over the past few years, an increasing number of operators in steam assisted gravity drainage (SAGD) in situ recovery of bitumen in the Alberta Oil Sands are becoming interested in the use of flow control devices (FCDs). Initial field trials by some operators of these devices have shown promise in improving steam chamber conformance, reducing incidences of steam breakthrough, high vapour production, and in addressing liner reliability concerns related to steam jetting.

While the application of FCDs is well-established in the conventional oil and gas industry to control gas and water coning, there are still a number of questions on how to implement FCDs optimally in SAGD. One major difference in the application of FCDs in SAGD compared to the conventional oil and gas industry is the high temperature environment with steam and elevated erosion risk.

The purpose of this paper is to present some practical considerations for the selection of FCDs and optimal completion FCD design for SAGD applications. In the first section, a discussion is presented on how to compare the performance of different flow control devices. Most devices have not been tested for SAGD, and there is a need for more comprehensive testing. The focus of the second section is on practical considerations for the installation of FCDs in a SAGD injection and production wells.
Downhole Remote Monitoring System for SAGD Observation Wells through Fiber Optic DTS
Authors: Zaini Faiz , Keough Daniel
Published: February 2017

As steam-assisted gravity drainage (SAGD) producers continue to look for methods for enhancing oil recovery, understanding the dynamics at play in the evolution of the steam chambers becomes critical. Steam thief zones introduce operational risks affecting the economic recovery of the bitumen. Sensitive reservoirs need careful monitoring to avoid compromising cap rock integrity and to detect steam breakthrough.

A need exists for real-time, spatially sensitive temperature monitoring in production, injection, and observation wells. Although such monitoring has been used in production and injection wells for decades, operators of SAGD observation wells (with typical two to six per pad) mostly used either piezometers for single-point pressure and temperature measurements and/or multiple-point thermocouple bundles. Distributed temperature sensing (DTS) application in these remote environments has been limited by availability of infrastructure with temperature-controlled environment and power supply in close proximity to the wellhead, which most DTS interrogation equipment requires.

In this paper we introduce and demonstrate the installation of a new stand-alone, low-power DTS solution to address the specific needs of remote observation wells within a northern Alberta SAGD field. An acquisition system with extended working temperature range and small geometry form is installed within enclosures equipped with temperature-control devices and zonal certification. Downhole temperature data is transmitted continuously over a cellular network to a secure server with data-trending software for ease of viewing.

The system was installed in February 2015 and the downhole temperature data accessible through web browser download during the field trial period.