bluuebunny/crossref_metadata_2025 huggingface dataset:
Integration of Pressure Transient Data in Modeling Tengiz Field, Kazakhstan – A New Way to Characterize Fractured Reservoirs
Authors: Pan Yan , Hui Mun-Hong , Narr Wayne , King Gregory , Tankersley Terrell H. , Jenkins Steve D. , Flodin Eric A. , Bateman Philip W. , Laidlaw Chris , Vo Hai Xuan
Published: April 2013

Tengiz is a supergiant oil field with 30 billion STBOOIP located in the Pricaspian basin of western Kazakhstan. The field produces from an isolated carbonate platform of Devonian to Pennsylvanian age, with a flat-lying central platform surrounded by a relatively steep depositional slope. Fractures are common and significantly enhance productivity in the outer platform and slope. Understanding the flow behavior of the matrix-fracture system is a key to successful field development.

The characterization of naturally fractured reservoirs is especially challenging due to a high degree of heterogeneity and uncertainty. When modeling carbonate reservoirs – and particularly those where fractures play a significant role – we lack a consistent and robust methodology for utilizing dynamic data collected from pressure buildup tests, production logging, pulse tests between wells, and from increasingly deployed permanent down-hole gauges. Instead, this data, which contain rich information about wells and reservoir, is often neglected in the conventional production history matching. This project aims to fill this technology gap to better characterize fractured carbonate reservoirs. We apply numerical well testing techniques with discrete fracture modeling to understand and characterize the fracture-matrix properties. The effective utilization of pressure transient data should narrow the uncertainty, improve the characterization, and help optimize field development.

First the numerical solutions from both Discrete Fracture Models (DFM) and Dual-Porosity Models using numerical reservoir simulator were validated against analytical pressure-transient solutions for a dual-porosity system. Next a systematic workflow to integrate single-well buildup test data into numerical models was developed based on synthetic case study results. Finally the new method was applied successfully to a sector model of Tengiz field. Some preliminary techniques were also developed to honor pulse test data and analysis results between wells with numerical simulation models.

Continuous efforts are being made to improve field-scale reservoir simulation models using dynamic and static data of fracture-matrix systems for more accurate field performance forecast in Tengiz. The successful integration of all types of data would have a big impact on reservoir management by potentially minimizing the number of wells to be drilled, maximizing the production from each well, and substantially increasing reserves.
History and Application of Resistance Electrical Heaters in Downhole Oil Field Applications
Authors: Sandberg Chet , Hale Arthur , Kovscek Anthony R.
Published: April 2013

Electrical heaters are seeing increased use in downhole applications. Low power heaters are used for viscosity flow assurance, paraffin buildup reduction and hydrate elimination. Electrical heating can be used where steam is not technically useful such as through permafrost, formations that are highly fractured with connectivity where SAGD is precluded and very deep wells with high pressure. Higher power electrical heating is now being use in formation stimulation for reduction of viscosity oil formations worldwide. The highest temperature applications are in the "Insitu Conversion Process" pioneered by Shell in the oil shale of Colorado. Polymer insulated heaters are used for temperatures under 400 °F and inorganic insulated heaters such as mineral insulated (MI) cable for temperatures as high as 1800 °F. The history of electrical heating applications and specific pilot results are reviewed. The paper reviews the technical characteristics of power source and temperature source electrical heaters. The paper reviews the history of electrical heater use in downhole applications, discusses the chemical, mechanical, and electrical challenges for downhole use and predicts the increased application of electrical heaters in the future. In South America there is a need for heaters as long as 7000 feet, operating at 4160 Volts with output of up to 350 watts per foot. The near well bore constraints of thermal diffusivity requiring a temperature source heater rather than a power source heater is discussed for use in Colorado Oil Shale applications. Process insitu time periods and energy balance for both conversion from Kerogen to bitumen; then upgrading the bitumen and to oil as light as 40 °API is also discussed. The time required for simple viscosity reduction heavy oil with suggested heater well spacing is reviewed.
A New Approach to Model Hysteresis and Its Impact on CO2-EOR Processes with Mobility Control Strategies
Authors: Beygi Mohammad R. , Delshad Mojdeh , Pudugramam Venkateswaran S. , Pope Gary A. , Wheeler Mary F.
Published: April 2013

Mobility control methods have the potential to improve coupled enhanced oil recovery and CO2 storage (CO2-EOR). There is a need for improved three-phase relative permeability models with hysteresis including especially the effects of cycle dependency so that more accurate predictions of these methods can be made. We propose a new three-phase relative permeability model with hysteresis applicable to different fluid configurations in porous medium under different wettability conditions. The model also includes compositional effects. Three-phase parameters are estimated based on saturation-weighted interpolation of two-phase parameters. The proposed hysteresis model is an extension of the Land trapping model but with a dynamic Land coefficient introduced. The trapping model estimates a constantly increasing trapped saturation for intermediate- and non-wetting phases. The model overcomes some of the limitations of existing three-phase hysteresis models for non-water wet rocks and mitigates the complexity associated with commonly applied models in numerical simulators. The model is validated using multi-cyclic three-phase water-alternating-gas experimental data for non-water wet rocks. Numerical simulations of a carbonate reservoir with and without hysteresis were used to assess the impact of the saturation direction and saturation path on gas entrapment and oil recovery.
A Successful Optimization Case of Drilling and Completion Operations Through Management Tools and Strategies
Authors: Silva Oscar R. , Silva Guden O. , Valderrama Luis I.
Published: April 2013

Sometimes, drilling optimization of an oil well does not come from a new technology or a new drilling tool, but instead, it may come from something as simple as "putting the house in order". This was the particular case of Castilla Field in Colombia in 2010–2011, where people had believed that all the drilling solutions were already applied. This paper shows how the drilling and completion (D&C) optimization of Castilla field was performed. The main problems were identified, and a model of 5 management strategies was implemented to reduce the D&C timing. The strategies of the model were applied under the following objectives: constant measuring, evaluation and monitoring of drilling indicators; Support field operations with strong drilling engineering planning criteria; Establish only one communication line through the office drilling engineer in charge of the project; Establish short, medium and long term planning and strategies, and then link them together as function of the Technical Limit "TL", and subsequently as an HSE function.

The initial evaluation was focused in four main areas: time savings & time to optimize, management indicators, human resources, and drilling operations characterization. The leader of the field has changed the current roles of the engineer in charge of the well from a logistics role to a genuine drilling engineer role. The short, medium and long term vision was applied throughout the well, well pad and campaign in advance. The slogan "Drilling the limit is not hurried up" was created. The technical limit (TL) goal was reached. The D&C times, and therefore costs, were reduced by up to 32% per year. Savings greater than USD50 million dollar per year were accomplished. The 2010 trial of Castilla field became the model for the rest of fields that are part of the company portfolio.

The degree of field optimization responds to the same extent at the level in which the gaps are found. It is believed that, as well as this model was applied successfully to other fields within the company, it also might also be applied to others companies. This paper resumes a model of 5 management strategies needed to purge and cure some bad habits that are against the D&C optimization in a field.
Application of Solvent Alternating SAGD Process to Improve SAGD Performance in Athabasca Bitumen Reservoir
Authors: Souraki Y. , Ashrafi M. , Ghahfarokhi A. Jahanbani , Torsaeter O.
Published: April 2013

Canada, Venezuela and United States contain the largest portions of heavy oil and bitumen resources throughout the world. The problem associated with this type of resource is very viscous fluid flow. The EOR methods applied to heavy oil reservoirs are mainly based on viscosity reduction processes such as heating the reservoir and solvent injection. Heating, in the form of hot water flooding, steam injection and in-situ combustion dramatically reduces the viscosity of heavy oil and bitumen, but it has green house gas (GHG) emission problems. Diffusion of solvents in heavy oil makes it lighter and therefore mobile and producible via production well. Diffusion of solvent is a very tardy process while time is very important in oil industry and any delay results in extra costs. Recently, hybrid methods like solvent and steam co-injection, steam alternating solvent injection (SAS) have been introduced to solve the mentioned problems, while benefiting from the advantages of heat and solvent.

Several simulation studies were performed to evaluate and compare the performance of steam assisted gravity drainage (SAGD) and steam alternating solvent (SAS) processes. Athabasca bitumen reservoir properties were used. Effects of some reservoir and fluid parameters such as thickness, porosity, vertical to horizontal permeability ratio and viscosity were assessed and compared for both processes. Experimental viscosity data of Athabasca and Cold lake bitumen were applied to evaluate the viscosity effect. In addition, sensitivity analysis was carried out on injection time intervals of solvent, solvent type and concentration.

Results revealed high recovery of bitumen and appropriate steam-oil ratio (SOR) for both processes. However, SAS showed better performance using hexane as a solvent. Lower porosity, vertical to horizontal permeability ratio and thickness resulted in higher SOR for SAGD process while they had no major effect on SAS. Higher concentration of injected solvent resulted in faster recovery performance and lower SOR. Pentane and heptane were used as alternatives for hexane to investigate the impact of the selected solvent. They divulged almost the same results as hexane. Different injection intervals of 3, 6, 9 months and a year were also studied and the analogous results were obtained.
Solar-Generated Steam for Heavy-Oil Recovery: A Coupled Geomechanical and Reservoir Modeling Analysis
Authors: Agarwal Anshul , Kovscek Anthony R.
Published: April 2013

The use of solar thermal steam generation for heavy-oil recovery has the advantage of reducing carbon dioxide emissions, as well as offsets the cost variability of steam generation due to fluctuations in natural gas prices. Daily cyclic fluctuations in steam injection rate associated with sunlight hours, along with hydrocarbon production and heating/cooling of rock cause changes to reservoir stress. This paper focuses on the dilation and compaction behaviors associated with continuous but variable-rate solar generated steam injection. Our approach integrates geomechanical models with the reservoir simulation model. The challenge with integrating geomechanics with reservoir models is to find accurate and sufficient data for stress field and orientation, dilation and compaction pressures, and the fracture pressure for the formation.

We evaluate the viability of a solar thermal steam generation system with natural gas back-up for thermal enhanced oil recovery (TEOR) in heavy-oil sands that includes geomechanical coupling with the reservoir. Coupled reservoir-geomechanical simulation runs with continuous variable steam injection were compared with the base-case uncoupled Tulare Sand steamflood project. Sensitivity analyses for dilation parameters were studied to understand their effects on the overall oil recovery and breakthrough times. Significant pore pressure variation to trigger compaction was not observed for reasonable day-time injection rates of up to 1000 BBL cold-water equivalent (CWE)/d in high permeability formations. The injection pressures were maintained much below the fracture pressure of the formation in all cases. To summarize, a solar thermal steam generation approach for thermal enhanced oil recovery is a promising technique for supplementing steam generation in areas with large solar insolation.
Extracting IF-THEN Rules from Numerical Data using Wang-Mendel Methods
Authors: Hao Minshen , Mendel Jerry M.
Published: April 2013

Knowledge and experiences are extremely important in the petroleum field. Most of the knowledge is in some expert's mind and it is not easy to validate and use it automatically.

In this paper, we introduce an approach to extract linguistic IF-THEN rules from numerical data. These kinds of rules are not only easy to implement in intelligent systems, but are also human-understandable. A soft clustering algorithm, the fuzzy c-mean (FCM) algorithm, is used to determine the MFs of the linguistic terms for each variable. Then, the Wang-Mendel (WM) method and two of its variants are applied to some historical data to extract IF-THEN rules. Finally, the generated rules are compared and validated using the given data.
Application of Toyota's Principles & Lean Processes to Reservoir Management: More Tools to Overload the Toolbox or a Step Change in Our Business?
Authors: Allan Malcolm E. , Gold David K. , Reese Dyke W.
Published: April 2013

Aera Energy LLC was formed in 1997 to be a low cost operator and producer in California. However, the low oil price in 1998-1999 forced an examination of all operations in the office and in the field. Cutting costs, better timekeeping, or reducing the scale of operations would not be sufficient without a step-change gain in efficiency. This step-change gain came from using principles and concepts developed in the automobile and construction industries. Toyota's twin pillars of just-in-time production and the ability of anyone to stop production rather than pass-on defects, coupled with level-loading of work processes, and reducing waste were introduced. Toyota's principles were enhanced by the addition of Last Planner concepts developed for the construction industry. When both were implemented for reservoir characterization and reservoir development work, significant process improvements resulted. The resulting improvements are now being used throughout the company to improve quality by removing waste and reducing errors, to measure processes, and to improve cycle times.

The unconventional diatomite reservoirs and oil sand reservoirs at the giant Belridge field produce 63,000 BOPD from 5,200 producing wells and 2,000 injection wells. The many drilling, completion, and workover rigs have a constant appetite for new wells. To maintain production and cost targets, everything in the office has to run reliably and efficiently at all times, plus support field operations.

Different aspects of Toyota's principles and Lean manufacturing are illustrated using reservoir characterization project work, day-to-day reservoir surveillance, and the development work needed to plan and schedule new wells. The processes and projects typically have multiple customers and suppliers—internal and external. Everyone, including knowledge workers, needs to work as a single system with a manufacturing mentality and to strive for continuous improvement. Customers of the knowledge work supplied by the geoscientists and reservoir engineers have benefitted greatly from the introduction of the Lean processes and the resulting smoother and more effective work flows. In 2011, the Development team's Lean activities were recognized by the Association for Manufacturing Excellence, and the team received the Manufacturing Excellence Award that recognizes "continuous improvement, best practices, creativity, and innovation."

The oil industry has a reputation of being slow to adopt new technologies and techniques. However, a Lean Manufacturing mentality introduces new ideas and ways of performing knowledge work that may change this paradigm while contributing to the bottom-line with reduced cycle-time and improved quality. A significant additional benefit is that geoscience and engineering professionals can spend more time doing creative work and less time fixing problems or reacting to system upsets—all while reducing waste.
A New and Practical Oil Characterization Method for Thermal Projects: Application to Belridge Diatomite Steam Flood
Authors: Zhang L. , Pieterson R. , Dindoruk B. , Stoffels P. , Fan Y.
Published: April 2013

Most of the oil characterization approaches for thermal recovery are designed for heavy oils at moderate temperatures where oil can be represented in very simplistic ways (i.e., ‘gas’ and ‘oil’). However, when oil is exposed to very high steam temperatures (i.e. 550°F), and/or the oil is lighter than the classical range defined for heavy oils and is exposed to wide spectrum of thermal effects such as distillation of the lighter ends, the conventional methods representing the interaction of steam and the in-situ fluids is not accurate. In many cases, we have to first evaluate the quality of the data, and then represent the average behavior with a single most likely fluid model per reservoir segment (plus other scenarios, as needed) to simulate the production performance. There is a need to develop a streamlined approach to bring such data into industrial simulators in a practical way.

In this study, we have developed a fit-for-purpose approach to generate a consistent PVT model over the whole reservoir, reflecting both pressure and temperature changes through the entire oil accumulation. The model represents the oil viscosity for wide spectrum of temperatures, from reservoir temperature to steam temperature (thermal process range). A systematic lumping scheme enables conversion of the characterized PVT model for numerical simulators with the minimal number of pseudo-components while still capturing the essence of thermal physics. To our knowledge, there has been no systematic study of this nature in the literature available yet.

We have tested the above approach in the Belridge Diatomite steam drive project. The study confirmed that steam flood incremental oil production in light oil reservoir is sensitive to the component lumping scheme because of distillation of the lighter ends. We also found that a five component PVT model, representing the physics in ‘fit-for-purpose’ dynamic simulation, best compromises between minimal number of components and physical description of the light oil behavior.
An Experimental Investigation of the In-Situ Combustion Behavior of Karamay Crude Oil
Authors: Zhao R. B. , Chen Y. X. , Huang R. P. , Castanier L. M. , Kovscek A. R.
Published: April 2013

In-situ combustion (ISC) is an effective thermal recovery process that provides an alternative to steam injection. Air is injected into a reservoir to oxidize a small portion of the hydrocarbons present thereby generating heat and pressure that enhance recovery. ISC suffers from fewer limitations than steam injection, but is not applied widely. One factor that has limited application of ISC is the difficulty of evaluating ISC candidates in the laboratory to obtain critical information such as crude-oil oxidation kinetics, combustion front propagation, and the burning qualities of various crude-oil components.

The Karamay Field (Xinjiang, China) has crude oil that is roughly 12.0°API and is a potential candidate for ISC. We have conducted a screening study to evaluate the likelihood of the success of ISC in Karamay. Questions of interest for Karamay include the fraction of the crude oil that is converted to fuel and the particular crude-oil components that become fuel for ISC. To investigate ISC properties of the oil, true boiling point fractions were collected from Karamay crude oil and the kinetics of oxidation of each fraction in porous media were measured using ramped temperature oxidation (RTO). The isoconversional approach is used to interpret the RTO results of each boiling point fraction. The approach obtains the reaction kinetics for a given rock/oil sample at identical reaction extent from multiple experiments with different heating rates.

The 500+°C boiling point fraction presents reaction kinetics most similar to the whole crude oil indicating that the crude-oil components in this fraction contribute the most to fuel production. Reaction kinetics of the whole oil appeared to be favorable for successful propagation of a combustion front. This prediction was validated by conducting displacement tests in a 1 m long combustion tube using reservoir sands. The Karamay crude oil demonstrated significant in-situ upgrading as a result of ISC. The initial gravity was 11.8 °API whereas the average gravity of the produced oil was 19.3 °API. Importantly, our results add to the knowledge base of both conditions for successful ISC as well as significant upgrading.
Drilling Challenge of Unstable Hole: Condition in Kilo Field: A Case Study in Southeast Asia
Authors: Tobing Jerry , Tanjung Erwindo
Published: April 2013

One of the drilling challenge in Kilo Field of Offshore North West Java Indonesia is unstable hole condition. The critical formation is named Main Massive with the dominant clay-rich shale lithology. The unstable hole had caused stuck pipe, casing delays, loss of expensive tools in the hole, and undesirable sidetracks.

Recently, there were 2 wells was drilled in Kilo Area. Based on the offset wells data drilled from this platform, there were some wells running in normal operation and the others were having unstable hole problems. All of the offset wells were using dispersed water based mud system in which generally, the drilling operation of those offset wells could be managed until casing run to the bottom. The recent 2 wells encountered unstable hole problem are KKNA-5 and KKNA-3ST development wells.

KKNA-5 was designed to drill from the new slot using the same mud system as the offset wells from surface until intermediate section. In production section, mud system was changed to inhibited polymer referred to laboratory test result of cutting samples from surrounding area. However the unstable hole problem was still happened causing stuck pipe and BHA lost in hole.

KKNA-3ST as reentry well also encountered same problem. The production section was drilled using inhibited mud system; however the unstable hole was uncontrolled while running the casing. The casing was parted and left in hole. The sidetrack drilling was decided using previous dispersed mud system, but again the casing was set shallower due to unable to run until casing point.

Preliminary root-caused analysis led to the mud material quality. However, following other drilling wells in other fields was drilled without similar drilling problem in Kilo area, which mean the uncertainty or material quality was diminished. The deeper engineering analysis was also conducted without carrying out unstable hole problems.

This field case study presents a new drilling challenge in Kilo Field. Further drilling study especially related to time-dependent wellbore instability shall be conducted, considering drilling operation of some offset wells was running smoothly. The integrating geomechanic study with drilling fluid design shall mitigate unstable hole problems in this area.
California Department of Conservation's Division of Oil, Gas, And Geothermal Resources: Orphan Well Program
Authors: Hesson, P. E. Bruce H.
Published: April 2013

The California Department of Conservation's Division of Oil, Gas, and Geothermal Resources (Division) supervises the drilling, operation, maintenance, and abandonment of wells so as to prevent, as far as possible, damage to life, health, property, and natural resources.

One of the Division's many programs involves orphan well elimination. A well is orphaned when the operator is defunct or when the Division determines through the formal order process that it is deserted. The California Public Resources Code allows, with the consent from the mineral rights owner and the Division, a different operator the opportunity to evaluate an orphan well's potential and to acquire ownership. In cases where an orphan well is not acquired by a viable operator and has been determined to be a public nuisance or hazardous, the Division can contract to have it permanently plugged and abandoned. The Division is funded through an assessment on oil and gas production, which also includes funding for the abandonment of orphan wells.

This paper will discuss the California Public Resource Codes (PRC) related to orphan wells, the process to declare a well orphaned, the procedures to allow an operator to acquire an orphan well, abandonment funding, the selection process for wells to be abandoned, State competitive bid abandonment contract requirements, abandonment project planning and oversight, several case studies, and the Division's orphan well program accomplishments.
A Comparative Thermal IOR Simulation Study with Experimental Design for Optimal Future Performance of a Heterogeneous Light Oil Reservoir
Authors: Al-Mudhafer Wathiq
Published: April 2013

Steamflooding has been widely used to improve oil recovery in heavy and light oil reservoirs. It has proved its efficiency to thrive the oil displacement and enhance the sweep efficiency by changing the reservoir and fluid properties, especially in heterogeneous formation. The reservoir under study is the main pay/upper sandstone member in South Rumaila oil field located in Iraq. This field, with a 58-year production history, has 40 production wells and is surrounded by an infinite active edge water aquifer from the east and the west flanks. Since the east flank is much less effective than the west one, twenty injection wells have been drilled at the east flank over the last 35 years. The formation depth is 10350 ft. sub-sea with a maximum vertical oil column of 350 ft. The average bubble point pressure of 2660 psi and the average reservoir temperature is 210°F while oil density is 34°API. In this study, a comparative thermodynamic simulation study has been done in conjugation with experimental design to investigate the main factors controlling the Steamflooding feasibility in improve oil recovery and to determine the optimal future Steamflooding scenario that has the maximum cumulative oil Production in a future production period.

Firstly, the thermodynamic reservoir simulator (CMG-STARS) has been applied to demonstrate the impact of steam flooding to enhance the sweep efficiency through this heterogeneous reservoir. A full factorial approach considering full interaction terms has been adopted to determine the optimal Steamflooding scenario considering four main factors to be changed in two-levels. The response in this approach is the cumulative oil production in twelve future production years. The factors are steam quality, steam injection rate, number of steam injection wells, and the steam temperature. For two levels of four factors in full factorial design, sixteen observations have been done according to the (2^k factorial design). The entire analysis of the current designed experiments have been performed by R statistical software packages. The regression model has been tested by ANOVA table, p-value, R Squared & R adjusted, and basic diagnostic plots and it has shown reliable evaluation. The results have shown that the steam quality, injection rate, and no. of wells have the most influence factor on the cumulative oil production in addition to some interaction rate that have no temperature. There is very limited effect of the temperature.

Among these runs, the optimal scenario, which has distinct target, has low levels of steam quality, flow rate, steam injectors, and temperature. The rationale behind these results is that the reservoir under study is light oil and has high heterogeneity at the east flank that lead to high steam distortion and spread. The optimal scenario has been compared with the base case without injection and has distinct different in cumulative oil production.
Weakly Emulsifying Surfactant Reduces Formation Damage and Enhances Well Productivity in Acid Stimulation
Authors: Xu Liang
Published: April 2013

Surfactant is a critical component used during acid stimulation. While many variables, such as interfacial surface tension, wettability, and compatibility with other acid additives, must be considered to tailor a surfactant to specific well conditions, the focus is on the most fundamental property of a surfactant, which is its emulsification tendency. The technical norm for surfactant applications in acidizing, however, is that a non-emulsifying (NE) surfactant should be selected to avoid the formation of tight emulsions. Tight emulsions are thought to block the oil and gas flow by plugging the pore throats in the rocks. While this concept is true to some degree, it neglects the ultimate purpose of surfactant use. In contrast, a weakly emulsifying (WE) surfactant is capable of generating transient oil in water emulsions with lower viscosity; thus, mobilizing the oil more effectively.

In this study, the primary difference between NE and WE surfactant is highlighted in terms of emulsion tendency and using preliminary production data from multiple wells in the Monterey formation.
Natural Convection in CO2-Based VAPEX
Authors: Javaheri Mohammad , Abedi Jalal
Published: April 2013

Vapor Extraction (VAPEX) is a promising technique for the recovery of heavy oils and bitumen in reservoirs where thermal methods cannot be applied. In this work, the effects of dispersion and viscosity variation in the boundary layer of VAPEX on natural convection are studied. Natural convection may happen in VAPEX, if the solvents that are used to decrease oil viscosity, increase its density. This can occur with carbon dioxide-based solvents. The reduction of the oil viscosity due to solvent dissolution can have a large impact on the onset of convection, by decreasing the critical Rayleigh number by up to two orders of magnitude. The analysis shows that the longitudinal Peclet number does not have a significant impact on natural convention; however, the transverse Peclet number is a crucial parameter in determining the critical Rayleigh number. The wave number increases with the Rayleigh number, but decreases with the transverse Peclet number. When the effect of viscosity is included in the analysis of boundary layer instability in VAPEX, natural convection may occur in highly permeable reservoirs, leading to a greater oil production rate. The current models that are used to predict the oil production rate in VAPEX do not consider this effect and underestimate the oil production rate in case natural convection occurs.
Portable Technology Puts Real-Time Automated Mineralogy on the Well Site
Authors: Ashton Tom , Ly Chi Vinh , Spence Graham , Oliver Guy
Published: April 2013

With the growing interest in the using hydraulically fracturing reservoirs both in main land USA and now globally, there has been a growing need to better characterize the reservoir to maximize hydrocarbon recovery while also reducing the overall cost in the recovery of the hydrocarbon. With current fracc-ing regimes relying on a large number of stages to ensure maximum recovery, which in many cases leads to upwards of 30% of these stages being unproductive. This reduces the overall profitability of well even with maximum hydrocarbon recovery. With the ongoing development of automated mineralogy tools, such as the RoqSCAN, there is now the ability to characterize a reservoir at the well-site in real-time and also rapidly in a laboratory.

In this paper we will review the current development of these mobile and ruggedized instruments using a real life project for Eagleridge Energy LLC, on their Burgess lateral well. The paper will show the application of automated mineralogical analysis of cuttings samples pre-drilling in defining stratigratic zones via mineralogy/elemental data. And then explore the application of the same data to assist, and in this case lead, the decision making process during directional drilling of the lateral well. The paper will also look at the use of the technology in defining tactical fracc-ing zone based on rock properties (e.g. ductility) determined from the mineralogical, elemental and textural data.

This paper will show that through the use of automated mineralogical instruments, such as the RoqSCAN, companies can pro-actively steer wells by identifying mineral changes within lateral borehole, indicating a deviation from the target zone. Additionally, this type of technology can be used to reactively steer by it ability to rapidly identification subsurface changes, such as unknown (undetected) faults. Finally the paper will show that through through the better characterization of this reservoir companies can reduce the risk accociated with the drilling of expensive lateral wells.
Water Management in Mature Oil Fields using Preformed Particle Gels
Authors: Goudarzi Ali , Zhang Hao , Varavei Abdoljalil , Hu Yunpeng , Delshad Mojdeh , Bai Baojun , Sepehrnoori Kamy
Published: April 2013

Excess water production is a major problem that leads to early well abandonment and unrecoverable hydrocarbon in mature oil fields. Gel treatments at the injection wells to preferentially plug the thief zones are cost-effective methods to improve sweep efficiency in reservoirs and reduce excess water production during hydrocarbon recovery. A recent gel process uses the preformed particle gels (PPGs) to overcome distinct drawbacks inherent in in-situ gelation systems, i.e. lack of control on gelation time, uncertain gelling due to shear degradation, chromatographic fractionation or change of gel compositions, and dilution by formation water.

This paper describes the results of PPG injection in both fracture and sandpack models where the experimental results were used to develop and validate mechanistic models to design and optimize the flowing gel injection for conformance control processes. Crucial properties gel such as in-situ rheology and swelling ratio in addition to oil recoveries were investigated. The water and oil permeability reduction factors were measured and modeled as a function of gel strength, rock permeability, and flow rate. The PPG transport models were successfully implemented in a reservoir simulator and validated against the laboratory experiments.
A Stochastic Model To Develop Braided Stream Reservoirs: Montalvo Field, Ventura Basin
Authors: Zahner Robert , Morris Peter , Ozgen Chet
Published: April 2013

The Montalvo field has produced 42 million barrels of oil from the 3000 foot thick non-marine fluvial Sespe formation. Pressure transient analysis suggests that individual reservoirs are less than 200 feet in width and have limited connectivity. Since detailed mapping of individual sands is virtually impossible, early development was focused on the bigger sand packages. This case study presents the methodology to pick stepout locations and evaluate bypassed reservoirs in a field that has produced for over 60 years.

With as many as 200 small-scale reservoirs at Montalvo, conventional structure and net pay maps are of limited use when picking locations. Venoco used a stochastic approach that identifies deposition trends with models that varied channel width, length, sinuosity, orientation and facies. Issues addressed include the lack of a common oil-water contact, significant variations in reservoir pressures, and transmissibility of faults. The geologic model was populated with over 1000 realizations then reduced to 133 by history matching fluid production and reservoir pressures in a dynamic model. An objective function was then used to pick the best 30 realizations for prediction runs. The authors concluded it was unrealistic to expect the model to predict recovery from individual wells, but it could identify trends and rank locations. Drilling results have confirmed this conclusion, with a wide variation in performance of the eight wells drilled since 2010 and an average estimated ultimate recovery (EUR) very close to predictions.

The methodology is especially relevant where operators hope to increase recovery in fields with a long production history, poor data resolution, multiple horizons and/or significant variation of reservoir quality. This work shows that it is possible to use reservoir modeling to identify oil reservoirs on a scale smaller than seismic resolution.
Flow Units: From Conventional to Tight Gas to Shale Gas to Tight Oil to Shale Oil Reservoirs
Authors: Aguilera Roberto
Published: April 2013

Core data from various North American basins with the support of limited amounts of data from other basins around the world have shown in the past that process (or delivery) speed provides a continuum between conventional, tight and shale gas reservoirs (Aguilera, 2010). This work extends the previous observation to tight oil and shale oil reservoirs. The link between the various fluids is provided by the word ‘petroleum’ in ‘Total Petroleum System’ (TPS) which encompasses liquid and gas hydrocarbons found in conventional, tight and shale reservoirs. Results of the present study lead to distinctive flow units for each type of reservoir that can be linked empirically to gas and oil rates and under favorable conditions to production decline. To make the work tractable the bulk of the data have been extracted from published geologic and petroleum engineering literature. The paper introduces a new unrestricted transition flow period in tight reservoirs that is recognized by a straight line with a slope of -0.75 on log-log coordinates. This straight line occurs as a transition between 2 linear flow periods.

Process speed is the ratio of permeability and porosity. The approximate boundary between viscous and diffusion dominated flow in gas reservoirs is estimated with Knudsen number which can be calculated from pore throat radius (a function of process speed). Viscous flow is present, for example, when the architecture of the rock is dominated by megaports, macroports, mesoports and sometimes microports (port = pore throat). Diffusion flow on the other hand is observed at the nanoport scale, which can occur in both tight and shale reservoirs.

The process speed concept has been used successfully in conventional petroleum reservoirs for several decades and in tight and shale gas reservoirs during the past 3–4 years. The concept is extended in this paper to tight oil and shale oil reservoirs, and hence to the complete petroleum system, with the support of core and drill-cuttings data. The approach permits estimating volumes of petroleum-in-place, differentiating between viscous and diffusion dominated flow in gas reservoirs and the contribution of each flow mechanism with the use of a unified diffusion-viscous flow model. This is valuable, for example, in those cases where the formation to be developed is composed of alternating stacked layers of tight and shale reservoirs, or where there are lateral variations due to facies changes.

It is concluded that there is significant practical potential in the use of process speed as part of the flow unit characterization and production performance prediction in unconventional petroleum reservoirs.
Group Testing: A Novel Approach To Increase The Effective Frequency Or Accuracy Of Well-tests Without Increasing Infrastructure Costs
Authors: Lin Yenting , Ortega Antonio
Published: April 2013

This paper presents a novel method to increase the well-testing frequency or accuracy without changing current infrastructure. In the current operation of automatic well-testing (AWT) systems, at any given time only one producer is connected to the testing facility in order to perform the flow rate measurement. Thus, AWT systems sequentially perform well-testing for a series of wells in the field, which may take as long as a few weeks for one round of testing, depending on how many wells are assigned to each AWT system. For a testing facility which uses a gravity based separator, the testing period is limited by the minimum time it takes to accumulate a measurable fluid sample in order to produce a sufficiently reliable measurement. In this scenario, low production rate wells are a key limiting factor, because it takes much longer for these to reach a measurable level. We use the "group-testing" concept and propose a novel approach where at any given time the fluid from several wells is diverted to the testing facility. Thus, what is measured is the "sum" of the production of the corresponding wells. Our proposed approach involves changing the combinations of wells (i.e., different combinations of wells are measured at different times) in order to ensure that it is possible to estimate the individual production rates of each well from a series of aggregate measurements. Because we connect multiple wells at the same time, the total fluid rate will be higher and the time needed to reach the level required for a reliable measurement will be reduced, thus making it possible to obtain more frequent well-testing data.

This process can be pre-programmed, automated and requires no-extra manpower in the field. For example, for a low production well it may take 8 hours to accumulate a minimum measurable sample. With our group testing, if we combine four wells together this level will be reached in just 2 hours. In this example, if 24 low production wells are connected to the AWT, the sequential well-testing method requires about 8 days to complete the testing, while our method only takes 2 days, which reduces the well-testing period by 75%.
Modified Inversion Technique for Determining the In-situ Stress Field
Authors: Shahri Mojtaba P. , Miska Stefan Z. , Yu Mengjiao , Ozbayoglu Mehmet E. , Zhang Jianguo , Majidi Reza
Published: April 2013

One of the major challenges of oil industry is to predict the in-situ stress field accurately. Accordingly, different techniques have been developed to predict the reservoir stress field in the past decades. Inversion Technique is a powerful method which was developed to determine the minimum and maximum horizontal stress components and their direction using fracturing data, i.e., leak-off tests or mini-fracture tests, by solving an over-constrained system of equations. As compared to other indirect methods, the actual fracturing data is used in this technique to back calculate the stress field.

In this paper, a new feature is added that enable us to determine the stress field using the data gathered during the production history of reservoir. In this approach, the effect of pore pressure changes on the reservoir stresses is incorporated into the Inversion Technique using constitutive equations of orthotropic rock model. Using the proposed technique, minimum and maximum horizontal stress components can be determined corresponding to different pore pressure during the reservoir life. According to the field data, the new formulation increases the prediction accuracy when fracturing data is gathered corresponding to different pore pressure. The proposed approach can be used for more accurate well design applications during the life of reservoir.
Quantitative Time-Lapse Seismic Integrated History Match in Delhi Field
Authors: Cui Q. , Hoffman B. Todd , Davis T. L.
Published: April 2013

Quantitative integration of time-lapse seismic and flow simulation in a CO2 enhanced oil recovery (EOR) process is an effective tool for performing dynamic reservoir characterization. The non-uniqueness of the history match process is largely reduced by quantitatively incorporating 4D seismic responses along with production data. Many papers in the literature had discussed the application of 4D seismic assisted reservoir simulation in either water flood or EOR reservoirs. However, very few of these publications have touched a stratigraphically complex reservoir with continuous CO2 injection strategy such as Delhi Field in Northeastern Louisiana. In this research, we proposed a time-lapse seismic assisted reservoir simulation workflow to improve history match of CO2 flood stage and reservoir modeling in in Delhi Field. The objective of this work also includes investigating the feasibility of incorporating time-lapse seismic data into history matching a very thin reservoir with unavailable historical water flood scheme. 4D seismic data was utilized in both qualitative and quantitative manner to assist reservoir model updating. A Petro-Elastic Model (PEM) was constructed to connect simulation outputs with seismic attributes. In this process, dynamic simulation results (pressure, saturation and CO2 density) along with elastic moduli were assembled into synthetic seismic attributed. The quantitative comparison of seismic inversion attributes and synthetic seismic attributes is an effective tool to evaluate previous history match process and guide the subsequent model updating.

This paper shows three level of history match process. The first level is preliminary model with poor production rate and pressure match. After that, a careful history match was performed by qualitatively incorporating time-lapse seismic interpretations. As a result, the production is greatly improved. The final stage of is to quantitatively compare synthetic and observed seismic attributes and use the objective function to further optimize the simulation model. The results of level two and three demonstrate that time-lapse seismic plays a significant role in Delhi Field reservoir simulation.

The contribution of this research consists of the following aspects. First, an updated and predictable model is important for the subsequent reservoir engineering work in Reservoir Characterization Project (RCP) at Colorado School of Mines (CSM). Secondly, this work provides an effective integration procedure of interdisciplinary dynamic reservoir characterization process for complex reservoirs. Thirdly, the optimized simulation results validate the effect of 4D seismic integration in continuous CO2 injection EOR process.