bluuebunny/crossref_metadata_2025 huggingface dataset:
Simplified Business Planning - A Business Unit’s Approach to Creating More Realistic, Higher-Return Plans; Faster
Authors: Kirk Graham , Kellogg Christopher
Published: June 2014

In the oil and gas industry, the term "business planning" brings visions of late nights, additional meetings, and countless hours spent collecting and reconciling large amounts of data. This negative connotation has been reinforced over the years as companies struggle to pull together the information they need to create realistic and achievable plans and to forecast future development to guide the growth of their business.

It is unfortunate that business planning has such a bad reputation as it is critical to the success of any company in any industry. In business planning, the goals are simply to select the best projects from a portfolio of opportunities to maximize the return on investment, while being able to effectively communicate the details of how the different scenarios were created to provide confidence in the decision to invest.

This paper describes a case study in which one of Occidental Oil and Gas Corporation (Oxy BU) business units improved a few key elements in their business planning process which helped them create a more realistic, higher return plan, faster.

The Oxy BU saw the potential rewards that improvements to their planning process could generate by improving their planning efficiency, reducing errors, and breaking out of the same painful cycle they had experienced in previous years.
Uncertainty vs. Variability: What’s the Difference and Why is it Important?
Authors: Begg Steve H. , Welsh Matthew B. , Bratvold Reidar B.
Published: June 2014

Technical professionals are often asked to estimate "ranges" for uncertain quantities. It is important that they distinguish whether they are being asked for variability ranges or uncertainty ranges. Likewise, it is important for modelers to know if they are building models of variability or uncertainty, and their relationship, if any.

We discuss and clarify the distinction between uncertainty and variability through strict definition, illustrative analogy and numerical examples. Uncertainty means we do not know the value (or outcome) of some quantity, eg the average porosity of a specific reservoir (or the porosity of a core-sized piece of rock at some point within the reservoir). Variability refers to the multiple values a quantity has at different locations, times or instances – eg the average porosities of a collection of different reservoirs (or the range of core-plugs porosities at different locations within a specific reservoir).

Uncertianty is quantified by a probability distribution which depends upon our state of information about the likelihood of what the single, true value of the uncertain quantity is. Variability is quantified by a distribution of frequencies of multiple instances of the quantity, derived from observed data. That both are represented by ‘distributions’ is a major source of confusion, which can lead to uncritical adoption of frequency distributions to represent uncertainty, and thus to erroneous risk assessments and bad decisions. For example, the variability of natural phenomena is sometimes well-approximated by normal or log-normal distributions, but such distributions may not be appropriate to represent the uncertainty in outcome of a single occurrence.

We show there is no objectively ‘right’ probability distribution for quantifying the uncertainty of an unknown event – it can only be ‘right’ in that it is consistent with the assessor's information. Thus, different people (or teams or companies) can legitimately hold different probabilities for the same event. Only in very restrictive, arguably unrealistic, situations can we choose to use a frequency distribution derived from variability data as a probability distribution to represent our uncertainty in an event's outcome.

Our experience as educators of students and oil & gas industry personnel suggests that significant confusion exists in their understanding of the distinction between variability and uncertainty. This paper thus provides a resource for technical professionals and teachers to clarify the distinction between the two, or to correct it where it has been wrongly taught, and thereby help to improve decision-making.
Transforming Portfolio Optimization through Reengineered Processes and Technologies
Authors: Charles Tashika , Zhakiyanov Berik , Moreland Colin , Back Michael , Bailey Erin
Published: June 2014

The process of upstream planning for the oil and gas industry has historically been a time consuming and inefficient process. The majority of effort is spent collecting data from multiple functional areas and organizational teams within an organization to form a holistic view of a company. By introducing an integrated solution that combines the opportunity catalog, economic analysis, and optimization into a single workflow, planners are experiencing efficiency gains, reduced time spent planning, and more accurate results. Through an analysis of the implementation of such a system at Chevron's Gulf of Mexico Business Unit (GOMBU), the challenges and benefits of implementing an integrated business planning approach as described will be demonstrated.

This paper will reflect on the systems, processes and workflows involved in the planning process at GOMBU both before and after deploying an integrated planning solution consisting of an opportunity catalog and linear optimization tool. This paper will also describe the challenges faced during the implementation and the benefits gained after the solution was deployed.

Method:

Define "Vision" and reason for move to linear optimization Discuss state prior to deployment Evaluate technical challenges with current state Review state after deployment Examine results and gained benefits Proposed model for integrated planning framework

Results & Observations:

Improved efficiency of portfolio optimization was significant, optimization time went from several weeks to days Portfolio optimization process was more fluid and responsive to changing business environments Secondary value generated to the entire organization in data integrity, consistency, management visibility into data, and traceability through opportunity maturation.

Conclusions:

Significant improvement in planning efficiency and accuracy achieved through implementation and execution of proposed architecture Integrated planning saves time, money and leads to significant value realization

Applications:

Learnings are applicable to any mid-to-large sized organization with any aspect of the planning process

Innovations:

Combination of opportunity tracking and planning into a single workflow Combination of Opportunity Catalog, Economics Engine, and Linear Optimizer into a single portfolio analysis package Cross-functional visibility and input into the plan and communication of results
A Management Decision Tool for Ranking Oil Sands Resource Development Opportunities
Authors: Dlugan M. , Pompa A.
Published: June 2014

A management decision-making and planning tool has been developed to provide a quick, high-level resource quality assessment of oil sands assets to enable economics-based ranking of investment opportunities. It is systematic and transparent, largely avoiding the subjectivity and human bias often associated with ranking assets for capital allocation.

The model utilizes the available reservoir characterization information (API gravity and petrophysical analysis including oil saturation, effective porosity, V shale, pay thickness), expected operating conditions (steam injection pressure, horizontal well lengths), and a reservoir risk assessment to predict the key performance metrics for an in situ oil sands project using SAGD (steam assisted gravity drainage) including oil rates, steam-oil ratio and recovery factors. The reservoir risk factor is a quantification of the production impact (lower expectations and/or increased uncertainty) from reservoir impairments based on expert opinions and reservoir simulation. These performance metrics can then be used to estimate expected overall economic potential (IRR) for a given asset. The ranking can be done at various levels: land sections, defined prospects, wellpad drainage areas, or at the individual (delineation) well level.

Predictive analytics techniques, in this case multi-variable linear regression, were used to construct the model. It was initially based on thermal recovery theoretical models for the SAGD process for predicting oil rates and a simple energy balance for predicting steam-oil ratio (SOR). Subsequently it has been updated via industry production data "fitting", or applying the actual performance data of various mature, operating wellpads to improve the confidence level of the model. The result is a hybrid model; science-based but influenced by real operating and production experience.

It has served as a primary tool used for strategic planning, in the setting of high-level performance targets (and probabilistic distributions thereof) for each of the assets. This tool has enabled a resource driven development strategy, allowing the company to focus technical resources on the assets that possess the greatest economic potential. Resulting business decisions include capital allocation (for additional delineation data) and more rigorous technical efforts (reservoir modeling and simulation) on the highest ranking prospects.
Discount Rate Development in Oil and Gas Valuation
Authors: Harden Clarence (Jim)
Published: June 2014

Oil and gas companies typically use discounted cash flow analysis in determination of the value of their oil and gas investments. "PV-10" is often accepted as the present worth of an oil and gas investment, but does a 10% discount rate represent the true cost of capital and include project-specific risk premium, or is it simply a rule-of-thumb? This original paper will discuss the factors that go into and how to calculate the weighted-average cost-of-capital (WACC) as the starting point to calculate the appropriate discount rate for their investment.
A Model Approach to the Emergency Preparedness and Response Process
Authors: Jensen Peter A.
Published: June 2014

Emergency Preparedness and Response and Business Continuity Planning are integrated into ExxonMobil’s structured approach to managing safety, security, health and the environment commonly referred to as"Operations Integrity Management System". This paper describes ExxonMobil’s Emergency Preparedness and Response Model and Process, with emphasis on its ongoing application. ExxonMobil strives to prevent emergencies from occurring. However, when emergencies do occur, the Model and Process defines ExxonMobil’s approach to preparing for and responding to the event(s). Our philosophy remains the same for an emergency that directly impacts us or one indirectly impacting our industry: establishing objectives that minimize impact on people, the environment, assets, and reputation (PEAR).

Our philosophy, objectives, tools, and processes are internal to the Model and Process, and integrate a tactical and strategic response. Internal and external resources ensure that our response is effective and scalable, on a 24/7 basis. Engaging these resources in training and exercises enhances response capability if a real emergency occurs. ExxonMobil’s Corporate Headquarters and Upstream, Downstream, and Chemical Companies have Emergency Support Groups (ESG) for each business unit. The ESG is focused on strategic support. Tactical support is derived from: Tier III Regional Response Teams (global coverage), U.S. based Tier II Strike Teams (personnel and equipment based), and numerous Tier I- Facility/Site Teams. ExxonMobil also contract with oil spill response organizations (e.g., Oil Spill Response, Marine Spill Response Corporation, and Marine Well Containment Company) for additional personnel and equipment. In the United States, use of the National Incident Management System’s Incident Command System (ICS) is required at the tactical level. ExxonMobil is in the process of implementing ICS, on a global basis, to improve preparedness and response.

ExxonMobil has benefited from the Model, Process, Teams, and Resources. Benefits include: Networking; Lessons learned and applied; and Increased personal knowledge. Team synergy and immediacy of effective response activities during emergencies have also validated training and exercises.

Emergency Preparedness and Response planning is essential for any organization. International and national laws and regulations mandate oil and gas companies to have emergency preparedness and response plans, resources, training, and exercises. The ExxonMobil Model and Process, which integrates strategy and tactics, provides an invaluable framework for preparing for and responding to emergencies.
Possible Mechanisms for Oil Recovery from Chalk and Sandstone Rocks by Low Salinity Water (LSW)
Authors: Hamouda A. A. , Valderhaug O. M. , Munaev R. , Stangeland H.
Published: June 2014

Low salinity water flooding is gaining much of attention for its potential in increasing oil recovery, in spite of the debatable working mechanism for both sandstone (SS) and chalk. Various mechanisms have been suggested in literature.

The objective of this work is to address oil/brine/rock (COBR) interaction and deduce thermodynamically possible product of the interaction, then verify with the experimental results. The experiments were designed to have most of the flooding with LSW as a secondary recovery method following seawater (SSW). This is to mimic the situation in most oil fields, which gone through seawater flooding and to contribute to the debatable discussion on the rule of LSW to enhance oil recovery as secondary or primary fluid.

From previous work in our laboratory, sulfate and magnesium have been identified as active ions in the seawater in altering chalk wettability to more water wet; hence they were also tested as single ions water flooding and imbibing fluids for both SS and chalk. This approach has contributed to our understanding of the possible reactions that occurs due to COBR.

From the SS part of the experiments, the results show indications of ion exchange, mineral dissolution processes and rock weakening causing fine migration. Mineral dissolution and ion exchange are not unexpected in presence of mineral such as, in general, kaolinite. The experimental results confirmed the simulated reaction between LSW and kaolinite from the increase of the pH and the resulted ions. In addition, the increase of the pressure drop detected during the flooding, could be related to the fine migration in addition to visual observation.

From the work performed on chalk, the results indicate fine detachment, which was enhanced in presence of Mg2+ ions as imbibing fluid at elevated temperature (70°C) for chalk. An increase of the pH was also observed for all flooding and spontaneous imbibition tests, especially with SO42- (for SS and chalk). In contrast to SS, chalk flooded with LSW showed reduction of pressure drop across the cores.
Assessment of Oil Recovery by Low Salinity Waterflooding from Laboratory Tests
Authors: Winoto Winoto , Loahardjo Nina , Morrow Norman R.
Published: June 2014

Increased secondary and tertiary oil recovery by low salinity water flooding has attracted widespread interest as a low cost improved oil recovery method. Field applications that give increased recovery by over about 2% OOIP are considered economically viable. Although the number of reported laboratory and field investigations is now approaching 200, no consistent conclusions have been reached as to the circumstances under which recovery is improved. Laboratory core floods provide a practical approach to investigation of necessary conditions for improved recovery. In seeking responsive rocks for investigation of recovery mechanisms, 19 sandstones were screened for low salinity effect (LSE) through decrease in residual oil after injection of dilute brine (LSE @Sor). The highest recovery given by a definitive bump in recovery, as opposed to small increase in oil cut, was 5% OOIP. Three rock types, Castle Gate, Berea Stripe, and Briar Hill, were selected for further study because of relatively high response. After the originally tested core plugs were cleaned and restored, two of the plugs gave robust residuals to high salinity flooding and no LSE @Sor; the third gave very high recovery by high salinity flooding but much reduced response to LS brine. Reproducibility of recovery behavior was tested for pairs of sister plugs. For all three core types, average LSE @Sor, if any, was much lower than the recoveries that led to their selection. The best performing sandstone, Briar Hill, was then tested further with sets of cores being taken from two additional quarried blocks, each weighing about 10 tons. None of the cores cut from these blocks gave significant tertiary response. The average recovery for outcrop rocks is much lower than the average for reservoir rocks. An unexpected conclusion from the study is that, because of the generally low response, outcrop rocks provide numerous examples of very little or no LSE @Sor.
Evaluation of Frictional Properties for Methane-Hydrate-Well Completion and Production
Authors: Yoneda Jun , Kakumoto Masayo , Miyazaki Kuniyuki , Katagiri Jun , Aoki Kazuo , Tenma Norio
Published: June 2014

During methane-hydrate production in offshore deepwater seabeds, there are concerns about the settlement of the seabed and the possibility that negative friction will occur along the production well. However, frictional properties of a deepwater well structure are not investigated. Here, friction tests were conducted on interfacial boundaries among a steel rod and sand and a steel rod and cement under high confining pressure. Three types of steel rods with different surface roughness, two types of silica sand with different particle sizes, and cement were used. A steel rod confined by compacted sand or hardened cement was pushed out at a constant displacement rate. The tests show that frictional strength of two kinds of interfacial boundaries increased linearly with confining pressure. In addition, the results confirmed the effective friction angle of the interface between a steel rod and sand and the cohesion of the interface between the steel rod and cement increases with the surface roughness of the steel rod.
Results of Reservoir Modeling of the Operation and Production of a Recompleted Gas Well in a Geopressured/Geothermal Reservoir in the Wilcox Formation, Texas, for Electricity Generation
Authors: Esposito Ariel , Augustine Chad
Published: June 2014

Reservoir modeling of production of hot geothermal fluid and natural gas from a geopressured reservoir in the Wilcox formation, Texas, for geothermal-electricity generation is carried out primarily on the basis of well-log data. The reservoir modeling takes into account operational considerations such as a constant target flow rate, a 30-year reservoir lifetime, and minimum wellhead pressure as well as uncertainty in reservoir parameters such as gas saturation and reservoir volume. The results of the reservoir modeling are presented and their relevance to other similar geopressured/geothermal wells with the potential for natural-gas production is discussed.
Installation of Complex Multilateral Wells With Standalone Sand Screens in the Vincent Field
Authors: Nettleship Gary , Palmer Anthony , Eshtewi Abdullah
Published: June 2014

The Vincent project is an offshore oil field developed by subsea multilateral (ML) wells with sand control. This paper provides an insight into how completion practices were developed to maximize well productivity and how they were balanced against risks for constructing ML junctions.

The fluids used for drilling and cleaning up openhole laterals can have a significant impact on well productivity in standalone-screen applications, especially with respect to sand-screen plugging. This paper details the development of openhole fluid selection and cleanup practices for completing long 7,000-ft+ horizontal laterals with standalone screens. The Vincent wells are more complex because of drilling trilateral wells that include two technology-advancement ML (TAML) Level-5 ML junctions requiring openhole connections. The paper identifies the key risks for installing the ML junctions in a weak formation, including risks imposed from cleanup practices.

The paper reviews the lessons learned during execution, how the ML-junction installation risks were mitigated, and how the Vincent wells were delivered with a well-performance meeting expectation.
In Situ Combustion Technology in the Later SAGD Process in Extra Heavy Oil Reservoir
Authors: Desheng M.. , Lanxiang S.. , Changfeng X.. , Xiuluan L.. , Erpeng G.. , Fengxiang Y.. , Xiaorong S.. , Yaoli S.. , Changjun D..
Published: June 2014

Steam assisted gravity drainage (SAGD) enjoys great advantages in the development of extra heavy oil reservoir such as high oil rate and favarable oil steam ratio. However, there are also disadvantages, such as intensive energy consumption, produced water recycle and disposal, that have impacts on the economics of SAGD projects. Furthermore, oil steam ratio declines and water cut rises when the SAGD comes into its later stage while great residual oil existing in the wedge zone. This paper proposes a new method, turning to in situ combustion (ISC) in the later SAGD, to improve the performance of the later SAGD. The feasibility and performance are both studied systematically. Firstly, a numerical model is established on the basis of reservoir and fluid parameters from a block in Xinjiang oil field, China, and then the performance characteristics in different stages of SAGD in extra heavy oil are studied. Particularly, characteristics of performance, features of temperature, pressure, steam chamber, distribution of residual oil in the later SAGD in extra heavy oil reservoir are deeply characterized. Combining these features and using physical simulation method, the feasibility of ISC in later SAGD in extra heavy oil reservoir has been discussed in terms of the effects of the oxidation kinetics characteristics, the thermal connectivity, the fuel supply, the coke deposit and the combustion front shape of extra heavy oil. Furthermore, the time when or before the steam chamber spreads to the edge of the SAGD well pair pattern is determined to be the optimum time to turn to ISC for the typical reservoir. By adding vertical wells for air injection in the middle of SAGD well pairs is the appropriate well pattern for ISC in the later SAGD. And perforating in the middle and lower interval is demonstrated to be the better method to control injection and production. Four stages in the process of ISC performance are determined and dissected. The study results indicate that stable combustion front shape and high production rate can be achieved after turning to ISC. Another 50.7% of the OOIP can be obtained in the ISC stage, regardless of 30% oil recovery in the SAGD stage.
Improving Reservoir History Matching of EM heated Heavy Oil Reservoirs via Cross-well Seismic Tomography
Authors: Katterbauer Klemens , Hoteit Ibrahim
Published: June 2014

Enhanced recovery methods have become significant in the industry's drive to increase recovery rates from oil and gas reservoirs. For heavy oil reservoirs, the immobility of the oil at reservoir temperatures, caused by its high viscosity, limits the recovery rates and strains the economic viability of these fields. While thermal recovery methods, such as steam injection or THAI, have extensively been applied in the field, their success has so far been limited due to prohibitive heat losses and the difficulty in controlling the combustion process. Electromagnetic (EM) heating via high-frequency EM radiation has attracted attention due to its wide applicability in different environments, its efficiency, and the improved controllability of the heating process. While becoming a promising technology for heavy oil recovery, its effect on overall reservoir production and fluid displacements are poorly understood. Reservoir history matching has become a vital tool for the oil & gas industry to increase recovery rates. Limited research has been undertaken so far to capture the nonlinear reservoir dynamics and significantly varying flow rates for thermally heated heavy oil reservoir that may notably change production rates and render conventional history matching frameworks more challenging. We present a new history matching framework for EM heated heavy oil reservoirs incorporating cross-well seismic imaging. Interfacing an EM heating solver to a reservoir simulator via Andrade's equation, we couple the system to an ensemble Kalman filter based history matching framework incorporating a cross-well seismic survey module. With increasing power levels and heating applied to the heavy oil reservoirs, reservoir dynamics change considerably and may lead to widely differing production forecasts and increased uncertainty. We have shown that the incorporation of seismic observations into the EnKF framework can significantly enhance reservoir simulations, decrease forecasting uncertainties and cope with the growing nonlinearity caused by the heating process for efficient and accurate reservoir forecasting.
Optimizing Field Development of Greenfield Polymer Floods using Experimental Design
Authors: Shook G. Michael , Walker D. L. , Jackson A. C. , Ruby N. H. , Poulsen A.
Published: June 2014

Waterflooding viscous oil suffers from poor displacement efficiency, requiring excessive volumes throughput for a given recovery. Heterogeneity reduces recovery further by reducing volumetric sweep efficiency. These can be mitigated by modifying injection viscosity with polymer. An improved mobility ratio reduces the throughput to achieve a given recovery, increases volumetric sweep efficiency, and reduces water production and associated handling costs. These three factors make polymer flooding an attractive alternative to waterflooding.

From a volumetric sweep perspective, there is no practical limit to the benefit of increased injection viscosity. However, increased fluid viscosity decreases injectivity, through damage (residual resistance factor) or increased resistance to flow with injection of a more viscous fluid. Injectivity issues can be overcome by decreasing well spacing, but at a capital cost. This introduces a de facto limit on polymer concentration; by reducing the concentration we can increase injectivity and increase well spacing, but at the expense of reduced macroscopic displacement efficiency and increased throughput. There are two decision variables (polymer concentration and well spacing) that have three consequences (injectivity, processing rate, and total volume throughput).

We have designed a workflow that maximizes NPV for given reservoir and flood properties by optimizing well spacing and polymer concentration. For given polymer concentration and spacing we analytically solve for injection rate vs. time and use that in fractional flow calculations to determine oil production vs. time. The workflow is automated, so a wide range of decision variables can be easily explored via Experimental Design. Surface response methods are then used to determine well spacing and polymer concentration that maximize net present value.

The methods developed for the optimization are presented, and the workflow steps are outlined. The method was applied to a field study; for the reservoir properties and under tertiary polymer flooding, the optimized set of conditions was 1900 ppm polymer and an injector-producer spacing of 700 ft. Injecting polymer prior to any water injection reduces the spacing to 380 feet and increases the polymer concentration to 2250 ppm, in large part because the low oil bank mobility dominates injectivity decline. This suggests an important design consideration of pre-conditioning the reservoir prior to instigating a polymer flood.
Integration of 4D Seismic Data for Well Optimization in SAGD
Authors: Masih Shahbaz , Rodriguez Maximo , Williams Andrew
Published: June 2014

The depositional environment at Statoil's Leismer SAGD demonstration project is dominated by a fluvial-deltaic system with complex geological features which present challenges for SAGD operations. An efficient monitoring tool that could combine geoscience data with production knowledge is vital for optimizing SAGD operational strategies. Time lapse (4D) seismic survey is one such monitoring tool. It can be integrated with wells and production data to prepare and optimize operational strategies. The pattern of growth of steam chamber is critical for well performance optimization. Steam chamber development dictates which reservoir areas are using heat efficiently and contributing to drainage of bitumen and increased production.

At Leismer, two 4D monitor seismic surveys have been conducted since the start of operations. The 1st monitor was acquired in 2012 to observe one year of SAGD performance and the 2nd monitor in 2013 to observe the performance after 2 years of operation. These surveys have been used to identify challenges to maximizing well pair productivity. Of primary concern is the effective distribution of steam along the entire horizontal section of the SAGD well pair. Other 4D monitoring benefits include, monitoring subcools with respect to reservoir heterogeneities, bottom water communication, steam chamber coalescence, baffle or barrier to steam chamber growth identification.

In this study, examples are presented to show how combining production and 4D seismic data has contributed to well pair optimization. Communication with bottom water in the early stages of SAGD, while rare, occurred in specific Leismer well pairs – analyses of production data combined with 4D seismic data helped identify steam loss into bottom water which drove steam injection strategy and improved well productivity. Another Leismer example shows how 4D seismic has been used to confirm a low reservoir roof at the toe of a particular well pair. This knowledge drove a change in injector well completion to optimize production. In the final example, it is shown how 4D seismic has helped analyze and confirm well conformance (heat distribution along SAGD well pairs) which is critical for uniform steam chamber development.

Based on Statoil's Leismer experience of applying results of 4D seismic analyses for well optimization, it can be concluded that 4D seismic has proven to be a very useful and value adding monitoring tool.
Updated Screening Criteria for Steam Flooding Based on Oil Field Projects Data
Authors: Hama M. Q. , Wei M.. , Saleh L. D. , Bai B..
Published: June 2014

Enhanced oil recovery (EOR) screening is considered the first step in evaluating potential EOR techniques for candidate reservoirs. Therefore, as new technologies are developed, it is important to update the screening criteria. Many of the screening criteria for steam flooding that have been described in the literature were based on data collected from EOR surveys biennially published in the Oil & Gas Journal. However, these datasets contain some problems, including outliers, missing data, inconsistent data and duplicate data, that could affect the accuracy of the results. Despite the importance of ensuring the quality of a dataset before running analyses, data quality has not been addressed in previous research related to EOR screening criteria. The objective of this current work was to update the screening criteria for steam flooding by using a database that had been cleaned. The original dataset included 1, 785 steam flooding field projects from around the world (Brazil, Canada, China, Colombia, Congo, France, Germany, Indonesia, Trinidad, U.S. and Venezuela). These projects had been reported in the Oil and Gas Journal from 1980 to 2012. After detecting and deleting the duplicate projects, only 626 field projects remained. To analyze and describe the results of the dataset, both graphical and statistical methods were used. A box plot and cross plots were used to detect and identify data problems, allowing for the removal of outliers and inconsistent data. Histogram distributions and box plots were used to show the distribution of each parameter and present the range of the dataset. New screening criteria were developed based on these statistics and the defined data parameters. The developed criteria were com-pared with previously published criteria, and their differences are explained in this paper.
Alteration of matrix wettability during alternate injection of hot-water/solvent into heavy-oil containing fractured reservoirs
Authors: Mohammed M. Almojtaba , Babadagli Tayfun
Published: June 2014

An alternate injection of solvent and hot water/steam called Steam-Over-Solvent injection in Facture Reservoirs (SOS-FR) has been recently suggested and tested by our research group. In this process, most oil is produced during the solvent phase and then hot water/steam phase is assigned, mainly to retrieve the solvent. Oil recovery during this phase is typically low due to limited thermal expansion in the case of oil-wet matrix, and because capillary imbibition and gravity drainage driven by viscosity reduction do not have a significant contribution to the recovery. Wettability alteration toward more water-wet state will, however, enhance these mechanisms.

Based on these facts, different wettability alteration agents were tested including cationic and anionic surfactants, ionic liquids, nano-fluids, high pH solutions, and low salinity water. The potential of these materials to modify the wettability of aged sandstone and limestone samples was evaluated using imbibition tests.

Berea sandstone (aged to be oil-wet) and Indiana limestone samples were saturated with heavy oil (3, 600 cp). After the wettability modification was confirmed using different tests, the SOS-FR method was applied. The process was initiated by soaking cores into solvent (heptane or diluent oil) and the oil recovery was estimated using refractive index measurements. Then, two different experimental schemes were followed. In this first scheme, different brines were used and the oil production readings were taken periodically. These experiments will yield additional oil recovery (and solvent retrieval) by capillary imbibition and enhance gravity drainage if the wettability alteration due to solvent effect in the previous phase and chemical injected in the subsequent phase was achieved. In the second scheme, the heptane was retrieved first by hot-water exposure and the capillary imbibition tests were performed to test the selected chemical additive solutions as the wettability alteration agents.

After conducting a total of 28 experiments, the most promising wettability alteration agents were marked and optimal application conditions (i.e., temperatures, injection sequence) were identified.
Induction and Radio Frequency Heating Strategies for Steam-Assisted Gravity Drainage Start-Up Phase
Authors: Ghannadi Sahar , Irani Mazda , Chalaturnyk Rick
Published: June 2014

Steam-assisted gravity drainage (SAGD) is the method of choice to extract bitumen from Athabasca oil sand reservoirs in Western Canada. Bitumen at reservoir condition is immobile due to high viscosity and its saturation is typically large that limits the injectivity of a steam at in-situ condition. In a current industry practice, steam is circulated within injection and production wells. Operators keep the steam circulation till mobile bitumen breaks through the producer and communication is established between the injector and the producer. The "start-up" (or "circulation") phase is ranging between three to several months. A variety of processes are used to minimize time of start-up phase such as: electro-magnetic (EM) heating either induction (medium frequency) or radio frequency (RF) ranges. Knowing the hot-zone size formed by steam circulation and benefit of simultaneous EM-heating techniques help better understand the start-up process and how to minimize the start-up duration. The aim of the present work is to introduce an analytical model to predict start-up duration for only steam circulation and also for with EM-heating. The results obtained from this study reveal that induction slightly decrease start-up time for frequencies smaller than 10 kHz, and it can reduce start-up time to 30% of original steam circulation for 100 kHz frequency.
An Innovative Modeling Approach to Unveil Flow Control Devices' Potential in SAGD Application
Authors: Riel A. , Burton R. C. , Vachon G. P. , Wheeler T. J. , Heidari M.
Published: June 2014

Sand screens with flow control devices (FCDs) have demonstrated significant potential in improving recovery in a Steam Assisted Gravity Drainage (SAGD) well pair. The premium wire-mesh sand control screens would have the capability to prevent sand flow into the liner in the event of a steam break-through. In addition the FCDs would improve steam conformance along the wellbore in the early time, and allow the producers to achieve higher production and lower Steam to Oil Ratios as well as restricting steam production if and when breakthrough at the producer occurred.

To better understand FCD behavior in SAGD operations, modeling of the different FCD designs has been attempted and has shown that steam breakthrough can be more effectively controlled utilizing devices that promote water flashing as fluids pass through them. With tools providing this type of control, steam breakthroughs in the producer can be more effectively restricted resulting in a better-produced fluid distribution along the wellbore. This also allows the producers to be operated with lower subcool margins without fear of sand production and the potential liner damage.

In order to validate the theory of improved performance and better thermal efficiency, a wellbore model coupled to a thermal reservoir simulator has been enhanced to more accurately model the impact of flow control devices on the reservoir/well performance. A collaborative effort has been initiated with the Computer Modeling Group (CMG) to develop a reservoir simulated FCD solution that will allow the user to enter characteristic performance curves for a variety of FCDs.

The development of the new keyword associated with ConocoPhillips FCD's mechanistic modeling has shown to be an improvement to the way that FCDs are currently modeled helping to unveil their potential for in SAGD and thermal recovery applications. Results from FCD pressure loss predictions and modeling of FCDs in the reservoir are provided to demonstrate the benefits of FCD use in SAGD operations.
A Novel High-temperature Gel to Control the Steam Channeling in Heavy Oil Reservoir
Authors: Wang Changjiu , Liu Huiqing , Wang Jing , Hong Cheng , Dong Xiaohu , Meng Qingbang , Liu Yongge
Published: June 2014

Controlling the steam channeling is a major challenge for increasing production in heavy oil reservoirs developed by steam injection. The conventional gel used in water flooding reservoirs always has poor heat resistance, so this paper proposed a novel high-temperature gel (HTG) blocking agent on the basis of a laboratory experimental study. The HTG consists of nonionic filler and unsaturated amide monomer with graft polymerization and crosslinking. The optimal gel system has a high gelling strength and controllable gelation time, which is achieved through incomplete orthogonal design method. Then the stability and plugging performance are studied through singular and parallel sand-pack experiments.

The results indicate that the HTG has strong salt resistance and dilution resistance. In addition, the HTG can still maintain high strength at 200°C for 72hr. The singular sand-pack experiments suggest that the HTG has good injectability that ensures the on-site construction safety. Moreover, the HTG has a high breakthrough pressure gradient after gelling and could keep the plugging ratio above 99.8% after gel breakthrough when the subsequent injected volume reaches 10PV. The results obtained in parallel sand-pack experiments show that the HTG can effectively plugging the steam channeling after injecting into the high permeability sand-pack from the production end, and force the subsequent steam to enter the low permeability sand-pack. That raises the producing degree of the low permeability sand-pack. Finally, the difference between high and low permeability sand-pack liquid production is reduced by 99.098%, indicating that the producing profile is tremendously improved, and the oil recovery is enhanced by 41.34%. As a result, the novel HTG blocking agent can be used to control the steam channeling in heavy oil reservoir.
Nodal Analysis for SAGD Production Wells with ESPs
Authors: Duncan Grant J. , Stahl Richard M. , Moseley Phillip E.
Published: June 2014

Steam Assisted Gravity Drainage (SAGD) is an enhanced oil recovery process whereby a long horizontal steam injection well is located above a long horizontal production well. Injected steam forms a steam chamber above the SAGD well pair, heating the reservoir rock and reservoir fluids. Heated oil (or bitumen) plus condensed steam flows down the sides of the steam chamber towards the production well. The condensed steam and bitumen are then lifted to surface with a downhole pump or by gas lift. Over the past decade, SAGD has become an increasingly popular method for extracting bitumen from Canadian oilsand leases that are too deep for surface mining, largely due to the high recovery factor from SAGD.

Nodal analysis for oil and gas wells enables the user to model well production or injection performance from the producing reservoir to the surface gathering system. Nodal analysis for well performance is based on the principle that reservoir inflow and wellbore outflow can be independently characterized as functions of flow rate. The single rate that balances the pressure losses in the inflow-outflow components with the pressure drop across the total system defines well flow. Nodal analysis is used to design new wells and optimize production or injection on existing wells. In addition, wellbore simulations are cheaper than instrumentation, meters or single well tests. Well evaluation software is the most popular package in Suncor's conventional production engineering toolkit because it is very accurate and easy to use.

Due to a rapidly increasing number of SAGD well pairs, Suncor required a tool that could accurately model these thermal wells. Over the past few years we worked with our software provider to develop nodal analysis for SAGD production wells, and we can now model SAGD producers with electric submersible pumps (ESP) with a high degree of confidence. The new SAGD nodal models quite closely match production rates, plus surface and downhole pressure and temperature data. Reliable and rigorous SAGD nodal models will enable improved decisions with respect to SAGD field development and production optimization.
Aquathermolysis and Sources of Produced Gases in SAGD
Authors: Thimm Harald F.
Published: June 2014

It has long been known that heavy oil and bitumen recovery by SAGD and CSS processes is accompanied by significant production of acid gases, as well as solution gas. Since the old laboratory studies of aquathermolysis from the 1970's and 1980's, there has been considerable development in the knowledge concerning production of methane and acid gases from Athabasca, Cold Lake, Peace River, Venezuela and Utah oil sands. It is found that both GOR and gas composition may vary with the deposits concerned. There is considerable divergence of opinion about the chemical origin of some gases, notably carbon dioxide. This affects the methods of control that may be available in operating individual reservoirs, and the matter is discussed. Also discussed will be the means of taking advantage of aquathermolysis phenomenon. It has been shown that both the GOR and gas composition of a SAGD project can be calculated from first principles. This permits estimation of the daily throughput of hydrogen sulphide and therefore allows a prediction or control of the requirements for sulphur recovery. The control of scale in SAGD plants has also been achieved by application of the current state of knowledge. Finally, there are implications for hydrogen sulphide release during loss of well control, an important regulatory aspect.
Feasibility Study of Using Transient Temperature Analysis to Evaluate Fracture Length in Cyclic Steam Stimulation Process
Authors: Wu Meng , Zeng Fanhua
Published: June 2014

In Cyclic Steam Stimulation (CSS), steam is usually injected above fracturing pressure into oil sands to achieve desired injectivity; thus fractures are generally induced. The induced fractures will affect heating and flow patterns and thus affect the choice of well spacing and steam injection strategies. Therefore, it is critical to evaluate fracture length for successful CSS projects.

Transient Temperature Analysis (TTA) is a technique which uses well-bore transient temperature data to estimate reservoir/wellbore characteristics. This paper discusses the feasibility of using TTA to evaluate the lengths of steam-induced fractures in cold lake oil sands by using wellbore transient temperature data in the soaking period of CSS. Numerical simulation model was first established based on history matching production data of a typical well in cold lake oil sands. Then the effect of different fracture lengths on temperature response in soaking phase was examined. Simulation results shows, in the middle and later period of soaking phase, linear relationships are found when temperature drop versus square root time are plotted. However, the correlation between fracture length and the slope is not clear. Based on the heated zone size and heated zone shape analysis at the very first moment of soaking phase, it is found the combined impact of reservoir permeability, reservoir thermal conductivity and fracture length determines the shut-in temperature response, which can be reflected on the slopes of the plots, with certain injection volume. But the qualitative representation of slope using fracture length, permeability and thermal conductivity cannot be found based on the results of finite difference based simulator. Aside from Finite difference method, simulation tools based on other numerical methods can be attempted to conduct TTA to evaluate the lengths of steam-induced fractures in CSS process.
Investigation of Interburden Dilution on Oil Sand Processability
Authors: Yang Xiaoli , Sedgwick Andrea
Published: June 2014

Surface mining of oil sands is generally limited to areas where the overburden thickness is less than ~75 m. Oil sands consist of a mixture of coarse sands, fine mineral solids, clays, formation water, and bitumen. Usually the orebody varies from 20 to 90 m in thickness, and the oil sand formation deposit is not homogeneous as it is intermingled with clays lenses (interburden). Bitumen content has been traditionally used as an indicator of ore processability. In fact, ores with a bitumen content of below 7% are considered uneconomical for processing. In this study, four types of ores were selected to evaluate the effect of adding two types of interburden with high clay contents on their ore processability. Ore processability was tested using the batch extraction unit. It was found that the interburden dilution does not always detrimentally affect the recovery. Depending on the ore grade, interburden dilution may boost the recovery for coarse grained ores, and depress the recovery for average and low grade ores. Current operational use of a maximum allowable fraction of interburden blended into oil sand feed may be overly simplistic. The results suggest that dilution to a maximum fines content of the blend is required rather than to a maximum fraction of interburden. Interburden effect on tailings settling behavior was also studied.