bluuebunny/crossref_metadata_2025 huggingface dataset:
Correlation of Stimulated Rock Volume from Microseismic Pointsets to Production Data - A Horn River Case Study
Authors: Rahimi Zeynal A. , Snelling P. , Neuhaus C. W. , Mueller M.
Published: June 2014

Hydraulic fracture monitoring from microseismic allows operators to optimize completions through a clear understanding and correlation of the reservoir response to stimulation. Furthermore it helps operators to improve production and avoid out of zone growth by identifying patterns of fluid movement, fracture growth and connectivity. These critical insights allow refinements to the treatment plan, and provide useful insights for long-term improvements regarding well spacing, well design, and completion design.

Shale reservoirs with very low permeability in the nano darcy range require a large fracture network to increase well performance. In these reservoirs, unless natural pre-existing fractures and faults have been reactivated and hydraulically opened to create a complex and well-connected network, pore pressure changes do not permeate far from the fractures. As a result, the microseismic pointset roughly corresponds to the size of the real fracture network which offers a means to estimate the stimulated rock volume (SRV). Although the producing fracture network could be smaller than the total SRV by a substantial percentage, it is expected that the effective network and the total SRV show a positive correlation. However, SRV is not the only indicator of well productivity. In a given SRV, the quality of the reservoir and parameters such as fracture conductivity and fracture spacing will affect production and can have a major impact on recovery calculations.

In this study, stimulated rock volumes obtained from microseismic pointsets are correlated with actual field production. The correlations are used to illustrate how this concept can optimize treatment design, well spacing, and stage spacing through correlation of the reservoir response to hydraulic fracturing and production data. The correlation between production and SRV for each well shows that larger SRVs result in higher well production regardless of the percentage of the SRV that contains proppant filled fractures. The direct relationship of the microseismic pointsets and production can be used to predict a new well's potential productivity immediately upon completion of the stimulation job. This suggests that a key completion strategy is to create a large and effective SRV to provide maximum recovery and well performance monitored microseismically to provide production prediction.
Towards Dynamic Control of In-situ Combustion: Effect of Initial Oil and Water Saturations
Authors: Kudryavtsev Philipp , Hascakir Berna
Published: June 2014

The performance and probability of success of in-situ combustion (ISC) is highly dependent on a multitude of parameters that define the reservoir conditions. The presence of reservoir heterogeneities makes it, therefore, practically impossible to predict a set of operational parameters that would provide efficient ISC performance. Dynamic control, whereby operational parameters are adjusted based on the reservoir conditions at the predicted combustion-front position, has the potential to significantly improve ISC performance. One-dimensional combustion tube experiments are the quickest method to determine the potential candidates for ISC. However, experiments conducted at average reservoir initial conditions do not provide data on the range of required operational parameters in a heterogeneous setting. Therefore, lab-scale experiments should be extended to screening tests by evaluating the ISC performance at the upper and lower limits of the reservoir initial conditions. To pave the way for dynamic control of ISC, this study investigates the effect of varying initial water saturation and initial oil saturation with one-dimensional combustion tube experiments on a bitumen sample (1.018 g/cm3) with high asphaltene content (∼35 wt%).

ISC performance change with varying initial oil and water saturations are discussed in terms of effluent gas composition, temperature profiles, total experiment time, oil recovery, behavior of fluid (oil, water, steam, and gas) front movements, X-Ray cross sectional images on postmortem samples, and the level of oil upgrading at different initial fluid saturations.

Our results indicate that the presence of initial water assists the combustion process and around 30% initial water enhances the ISC performance which can be maintained by steam injection prior to ISC if reservoir initial saturation is less than 30%. Moreover, initial oil saturation has been found to be the most critical parameter which defines the amount of fuel formed, and as a consequence, the heat generated.

The findings provide a significant improvement in our understanding of optimum operational conditions for a range of initial fluid saturations, bringing us one step closer to dynamic control of field-scale ISC.
Evaluation of Four Thermal Recovery Methods for Bitumen Extraction
Authors: Mukhametshina A. , Morrow A. W. , Aleksandrov D. , Hascakir B.
Published: June 2014

Around 70% of the world's bitumen resources are deposited in Western Alberta. Surface mining is applicable only to 20% of the total reserves, and in-situ cold production can only be effective to recover the 5% of the initial bitumen in place. This low extraction yield mainly stems from the high viscosities of bitumen, which can be reduced dramatically with the application of thermal recovery. However, economically viable and technically feasible bitumen extraction with thermal methods is challenging. There are also a range of adverse environmental issues associated with thermal methods. As conventional resources decline and since conventional recovery methods are insufficient to extract unconventional reserves effectively, it is necessary to address these issues associated with thermal recovery methods.

In this study, we evaluated the recovery characteristics of a Canadian bitumen (8.8 °API-53,000 cp, at 21 °C) with four thermal recovery methods. A two-dimensional physical model was used to evaluate the performances of Steam-Assisted Gravity Drainage (SAGD) and Hot Water Injection (HWI) with SAGD well configuration. Steam Flooding (SF) and In-Situ Combustion (ISC) experiments were performed with two separate one-dimensional experimental set-ups.

Experimental conditions were maintained identical at reservoir average conditions. The effluent gas composition, temperature profiles, oil recovery, behavior of fluid (oil, water, steam, and gas) front movements, and the level of oil upgrading were discussed by considering the environmental and economic constrains of the processes. Furthermore, core samples were extracted from the model to evaluate and visualize the sweep efficiency. Experimental findings reveal that ISC yielded the highest (∼90 wt %) and HWI the lowest (∼33 wt %) oil recoveries. In terms of environmental footprints, SF produced the highest amount of gases per barrel oil production, and HWI resulted in the lowest gas production. Among HWI, SAGD, and SF, energy consumption was the greatest in SAGD and the worst sweep efficiency was obtained with SF. Our results recommend a hybrid utilization of thermal recovery methods, specifically HWI with ISC for the extraction of this bitumen. HWI prepares the reservoir for ISC by aiding to increase reservoir temperature and reducing the reservoir heterogeneities with hot water distribution.
Characterization of Encapsulated Oil as an Additive to Water-Based Drilling Fluids: Operational Improvements in Lubricity, Drag, and ROP
Authors: Schuh F. J. , Coragliotti A. , DiCicco C. D. , Nagatani R. A. , Rea A. , Carlton T. , Johnson P. , Noble R.
Published: June 2014

Description of Proposed Paper

As the drilling industry moves towards extended-reach wells in more challenging formations, the need to identify operational solutions (e.g., drilling fluids/lubricity additives) to reduce friction, torque, and drag has become more important. Additionally, as the industry looks to maximize the use of water-based drilling fluids (to benefit from lower drilling fluid costs and improved environmental profile), the need to find novel additives that can improve lubricity has become more pressing. However, current methodologies for reducing downhole friction in horizontal wells generally involve reactive addition of lubricant products that are broadly acting, that may adversely affect the rheology of the fluid system, or that may dissipate or degrade over time. To address the need for new additives, a novel biotechnology method for encapsulating oil in polysaccharide-based polymers has been developed that selectively delivers high pressure lubricants at areas of high shear, pressure, and friction (e.g., between the drill string and formation or casing and also between drill bit and formation).

Application

Due to the protection afforded by encapsulation, this targeted friction inhibitor can be proactively added to water-based drilling fluid systems, where it circulates through the system until conditions are met to break the capsule and release lubricant. Observations in laboratory and field testing suggest potential operational improvements in running casing, reduction of torque/drag, reduction of bit balling, and faster Rate of Penetration (ROP) from targeted lubrication.

Results, Observations and Conclusions

Our characterization of encapsulated oil has shown the ability to reduce the coefficient of friction by over 80% in water-based mud formulations in the laboratory. In field-scale testing at the Catoosa Testing Facility, we have observed reductions in drag of up to 50%, reductions in torque of up to 45%, and up to 20% improvement in Rate of Penetration (ROP) in horizontal drilling after addition of encapsulated oil to a water-based polymer mud system. These results were substantially improved relative to observed results in an exploratory field well, in which ROP increased by up to 216% after addition of encapsulated oil in a saturated sodium chloride drilling fluid system.

Significance of Subject Matter

Our field testing and characterization in the laboratory and field have demonstrated the utility of adding encapsulated oil to a water-based mud-system to drill horizontal wells to improve the operational efficiency of drilling.
The Toxicity Characterization and Detoxification of two Formaldehyde-Releasing Oilfield Microbial Control Additives
Authors: Fallahtafti Shirin
Published: June 2014

An increased awareness of the environmental impact and operational cost associated with freshwater usage in energy production has shifted industry interest towards replacing freshwater sources with produced water in oilfield stimulation applications. Produced water often contains high concentrations of bacterial assemblages, which can cause operational challenges such as corrosion, slime formation, and souring. Microbial control agents are subsequently necessary to manage the poor water quality of most produced water sources. However, such chemicals are highly reactive and relatively unspecific, making their toxicity both a performance metric and an ecological, human health, and disposal concern. Given the advantageous biological activity of microbial control agents, controlled detoxification following use is a pertinent factor in responsible hazard management. Formaldehyde-releasing agents are a widely used category of microbial control additives which slowly and continuously release small amounts of formaldehyde, a toxic environmental pollutant and known human carcinogen. This research evaluated the acute (short-term) aquatic toxicity of two liquid formaldehyde-releasing microbial control additives, identified necessary parameters for their detoxification, and measured the resulting change in their toxicity over time, using a light-based acute toxicity test. The additives investigated were a tetrakis(hydroxymethyl)phosphonium sulfate (THPS)-based product (approximately 75% active by weight), and a 1,3-dimethylol-5,5-dimethylhydantoin (DMDMH)-based product (approximately 70% active by weight). Laboratory results suggest that the THPS-based additive was three times more toxic than the DMDMH-based additive on a percent volume basis, and pH was an important factor in THPS toxicity. Data were consistent with a maximum sixfold decrease in DMDMH toxicity for a 0.05% (v/v) solution following eight days of aeration at 0.15±0.05 liters per minute (LPM) (corresponding to a total of 172.8 LAir/mLSample), and more than a twelvefold decrease in THPS toxicity for a 0.05% (v/v) solution following a pH increase and eight days of aeration at 0.15±0.05 LPM (corresponding to a total of 172.8 LAir/mLSample). Aeration alone decreased the toxicity of DMDMH over the course of eight days, while a combination of aeration and pH increase were necessary to decrease the toxicity of THPS over the same time period. This work presents a proof of concept for a relatively simple and cost effective detoxification of the evaluated additives and highlights the key parameters for this process.
A Critical Review of Hydraulic Fracturing Fluids over the Last Decade
Authors: Al-Muntasheri Ghaithan A.
Published: June 2014

Hydraulic fracturing is a well-established process to enhance productivity of oil and gas wells. Fluids are used in fracture initiation and the subsequent proppant and/or sand transport. Several chemistries exist for these fluids. This paper summarizes the published literature over the last decade (90+ technical articles) and captures the advances in the design of water-based fracturing fluids. Despite their old introduction, guar-based polymers are still being used in fracturing operations for wells at temperatures less than 300°F (148.9°C). In order to minimize the damage associated with this class of polymers, the industry attempted several approaches. These include the use of lower polymer concentration in formulating these fluids. Another approach was to alter the crosslinker chemistry so that one can generate higher viscosity values with lower polymer loadings. Moreover, the industry shifted towards the use of cleaner guar-based polymers. The reason is the fact that commercial guar contains a minimum of 5 wt.% residues that cause damage to proppant packs. With fracturing deeper wells in hotter reservoirs, the need arose for a new class of thermally stable polymers. Thus, the industry shifted towards polyacrylamide-based polymers. These synthetic polymers offer sufficient viscosity at temperatures up to 232°C (450°F). Examples included 2-acrylamido-2-methylpropanesulfonic acid (AMPS) and copolymers of partially hydrolyzed polyacrylamide (PHPA)-AMPS-vinyl phosphonate (PAV). To address the challenge of high pressure pumping requirements on the surface, high density brines have been used to increase the hydrostatic pressure by 30%. On the breakers chemistry, new breakers were introduced. These breakers decrosslink the gel by reacting with the crosslinker. In order to minimize the environmental impact of using massive amounts of fresh water and to minimize costs associated with treating produced water, the use of produced water in hydraulic fracturing treatments has been reported. In addition, the paper captures the advancements in the use of slickwater where use is made of drag reducing agents (PAM-based polymers) to minimize friction. The paper highlights the first use of breakers that were introduced to improve the cleanup of these drag reducers. For foamed fluids, new viscoelastic surfactants (VES) that are compatible with CO2 are discussed. The paper also sheds light on the use of emerging technologies such as nanotechnology in the design of new efficient hydraulic fracturing fluids. For example, nanolatex silica was used to reduce the concentration of boron used in conventional crosslinkers. Another advancement in nanotechnology was the use of 20 nm silica particles suspended in guar gels. The paper provides a thorough review on all of these advancements.
Evaluation of CO2-EOR and Storage Potential in Mature Oil Reservoirs
Authors: Saini Dayanand , Jimenez Ivan
Published: June 2014

The selection of candidate reservoirs for future CO2 enhanced oil recovery (EOR) and storage projects greatly relies on methodical screening and detailed site specific evaluations. Once suitable reservoirs are identified in an initial screening for further evaluation, CO2-Prophet screening model could be used for a better understanding of proposed EOR project performance and site specific incidental CO2 storage prior to launching detailed and time consuming reservoir simulation studies. This paper reports on the use of publicly available geological and reservoir data and CO2-Prophet model for performing such analysis for two deep mature light oil reservoirs situated in the Kern County, California. In initial screening, these reservoirs have already been found amenable for CO2-EOR and storage.

Often, calibration of CO2-prophet model is either overlooked or just performed for achieving a material balance for oil and water phases. In addition to commonly used calibration step that involves a match for field water cut versus cumulative oil recovery history since waterflooding to achieve material balance for oil and water phases, we propose the use of an average gas-oil ratio match plot for obtaining a reasonable material balance for produced gas phase. A reservoir specific calibration of CO2-Prophet model for obtaining material balance for all three phases is aimed to increase confidence in future performance prediction results. We describe calibration procedure of the CO2-Prophet model in detail and use appropriately calibrated models for predicting CO2-EOR performance and incidental CO2 storage potentials in the reservoirs which have been already found ameable for CO2-EOR and storage in initial screening.

Beyond EOR based volumetric predications or other simple estimations made in initial screening of candidate reservoirs, appropriately calibrated CO2-Prophet model can provide more robust and reservoir specific estimates of CO2-EOR and incidental CO2 storage potential for a candidate reservoir. Such approach can be used for making initial business decisions such as selection of propective pilot sites or field acquisition while avoiding the need of detailed reservoir simulation studies. The results presented in the study clearly demonstrate that deep and mature light oil reservoirs of Kern County, California have potential for large scale (injection of more than 1 million metric tons of CO2 per year) CO2-EOR and storage projects.
An Integral Type Curve for Managing Cyclic Steam Processes
Authors: Gentile Lauren , Ershaghi Iraj
Published: June 2014

In this study we suggest a procedure to examine cumulative cycle response vs. cumulative injection in cyclic steam stimulation (CSS) application. This integral process is aimed at capturing the residual effect of prior steam cycles as well as de-saturation and re-saturation of pore volume in the vicinity of the wellbore. The proposed plotting method provides a diagnostic tool for examining the impact of operational factors and can serve as a lumped parameter predictive tool given the actual responses of some prior cycles.

Calibrated cumulative plots are first developed from the early cycles and predictions are shown for successive cycles. The proposed approach is providing a workable graphical tool that can capture both the improved or deteriorating condition exhibited on cycle responses. It can then help in the design of optimal planning of injected steam for successive cycles.
Sensitivities of Fractured Horizontal Wells in Shale Gas Plays to Technical and Economic Parameters
Authors: Carratu J. C. , Ozkan S. , Ozkan E.
Published: June 2014

Sensitivities of fractured horizontal wells in shale-gas plays to selected technical and economic parameters are discussed. An example data set is used and the low, base, and high values of the sensitivity parameters are considered. Technical performances are analyzed by using an analytical trilinear-flow model and the results are presented in the form of productivity indices, tornado charts, and the derivative of productivity index with respect to the sensitivity parameters. The sensitivities of economic indicators, such as net present value, internal rate of return, and the break-even prices are determined through a discounted cash flow model. The results indicate that the fractured horizontal well performances in shale-gas plays are relatively insensitive to natural fracture permeability and moderately sensitive to the distance between hydraulic fractures. Similarly, the hydraulic fracture permeability and half-length appear to have moderate influence on productivity. The permeability of the shale matrix and the density of the natural fractures, however, have the largest influence on productivity. For favorable project economics, optimal design of well construction and stimulation is important; however, the sensitivity of project economics to well construction and stimulation treatments is not high enough to convert a poor performer to a good one. It is essential to have good reservoir qualities to begin with for optimum well completion and stimulation design to lead to favorable economics.
Green Chemistry versus Full Chemical Disclosure and the Surrounding Industry Struggles and Perceptions
Authors: Sharp M. E. , Goudie D. R.
Published: June 2014

Given the social and political climates surrounding the oil and natural gas industry in North America, and more specifically hydraulic fracturing, the health, safety and education of the public and employees of operating companies is paramount. The two most common approaches being used to achieve this are using "Greener" chemistries and Full Chemical Disclosure. This paper investigates the characteristics of these two approaches, the differences between them, and the issues facing each.

One approach to protecting the health and safety of the public is by applying environmentally responsible processes, materials and equipment, also known as being "Green". Additionally the industry is striving to be as transparent as possible with public, state and federal agencies. Herein lies the tension between these two approaches: Full Chemical Disclosure is not the same as using Green chemistries. Green chemistries are being developed across the industry and contain vast amounts of intellectual property (IP) and proprietary knowledge. In order to protect the IP of these chemistries, not all of these will be available for full disclosure. This presents a major challenge in communicating with the public, which is demanding complete transparency based on the right to know what is being injected into oil and gas formations, usually far below potable water zones.

There is no universal industry definition of Green. Much of the meaning associated with the term is in the eye of the beholder. Compounding the issue, there are multiple state and federal regulations that outline what full disclosure entails. There are now 25 U.S. states that require some form of disclosure of chemicals used in hydraulic fracturing operations, up from only six states in 2011, very few of which have the same set of criteria.

This paper contains information that compares and contrasts the two approaches that are generally accepted in the industry: Green and full disclosure. It also covers state and federal regulations and some of the issues that surround them. In order for everyone to move forward on a united front, a committee of industry, state, and federal members should be formed to develop an accepted definition of Green.
Production Analysis of a Niobrara Field Using Intelligent Top-Down Modeling
Authors: Haghighat S. Alireza , Mohaghegh Shahab D. , Gholami Vida , Moreno David
Published: June 2014

Unconventional hydrocarbon resources are going to play an important role in the US energy strategy. Conventional tools and techniques that are used for analysis of unconventional resources include decline curve analysis, type curve matching and sometimes (in the case of prolific assets) reservoir simulation. These methods have not been completely successful due to the fact that fluid flow in unconventional reservoirs does not follow the same physical principles that supports mentioned analytical and numerical methods. Application of an innovative technology, Top-Down Modeling (TDM), is proposed for the analyses of unconventional resources. This technology is completely data-driven, incorporating field measurements (drilling data, well logs, cores, well tests, production history, etc.) to build comprehensive full field reservoir models.

In this study, a Top-Down Model (TDM) was developed for a field in Weld County, Colorado, producing from Niobrara. The TDM was built using data from more than 145 wells. Well logs, production history, well design parameters and dynamic production constrains are the main data attributes that were used to perform data driven analysis. The workflow for Top-Down Modeling included generating a high-level geological model followed by reservoir delineation based on regional productivity, reserve and recovery estimation, field wide pattern recognition (based on fuzzy set theory), Key Performance Indicator (KPI) analysis (which estimates the degree of influence of each parameter on the field production), and finally history matching the production data from individual wells and production forecasting. The results of production analysis by Top-Down Modeling can provide insightful guidelines for better planning and decision making.
Simulation Study of CO2 Huff-n-Puff Process in Bakken Tight Oil Reservoirs
Authors: Yu Wei , Lashgari HamidReza , Sepehrnoori Kamy
Published: June 2014

Advancements in horizontal drilling with hydraulic fracturing have enabled commercial oil production from Bakken tight oil reservoirs. However, the primary recovery factor remains very low (less than 15%), resulting in the high volume of oil remaining in place. Hence, it is extremely important to investigate the application of enhanced oil recovery methods. Carbon dioxide (CO2) injection as a huff-n-puff process is a preferred approach to improve oil recovery in tight reservoirs. In this work, we present the effect of CO2 molecular diffusion and performed a series of sensitivity studies to quantify the impacts of reservoir properties such as permeability and fracture properties such as fracture half-length, fracture conductivity, number of fractures, and operation parameters such as CO2 injection rate, injection time, soaking time, number of cycle of CO2 huff-n-puff and CO2 diffusivity on the CO2 huff-n-puff process for enhanced oil recovery in the Bakken Formation.

A numerical model was built using the typical reservoir and fracture properties from Middle Bakken to simulate CO2 huff-n-puff process. In this process, we consider CO2 molecular diffusion term to swell oil in matrix since Darcy velocity is negligible due to low permeability. The numerical model was validated with field production data from a horizontal well in Middle Bakken. Based on the history matching results, the relative permeability curves such as water-oil relative permeability and liquid-gas relative permeability, are obtained. Furthermore, the wettability for the Middle Bakken is found to be weak water wet. Simulation results show that the most important parameter is CO2 injection rate, followed by CO2 injection time, number of cycle, CO2 diffusivity. The other parameters such as fracture conductivity, CO2 soaking time, permeability and fracture half-length are less sensitive based on the range investigated in this study. The range for the incremental oil recovery factor at 30 years of production is obtained as 2.5% - 9.4%. This work can provide fundamental understanding of the key parameters controlling the CO2 huff-n-puff process for enhanced oil recovery in the Bakken Formation.
CO2 Injection for Enhanced Gas Recovery
Authors: Kalra Sumeer , Wu Xingru
Published: June 2014

Literature shows that there is a significant amount of natural gas available for enhanced recovery in the depleted reservoirs; at the same time, the depleted gas reservoirs are a proven storage facility for Carbon Dioxide (CO2) storage in terms of reservoir integrity. Conceptually, injecting CO2 into a depleted gas reservoir will not only potentially rejuvenalize the gas production, but will also store the greenhouse gas in a proven subsurface formation.

Study on CO2 phase behavior in subsurface conditions shows that CO2 most likely will be in super-critical state which exhibits liquid-like density and gas-like viscosity. These properties are favorable in displacing natural gas reservoirs in volumetric and pore scale sweep efficiency. Using numerical reservoir simulation on a synthetic case with multiple scenarios, this paper identifies the most amenable characteristics of a reservoir for enhancing gas production by injecting CO2 and analyzes the parameters influencing this secondary recovery process. In the paper, reservoir depth, depletion pressure ratio, aquifer activity, inclination angle, reservoir heterogeneity with various permeability arrangement, injection rate, and producer bottomhole pressure will be studied on the synthetic model. Furthermore, this paper will quantify the amount of natural gas which can be produced and CO2 that can be stored in an ideal case using economic matrix.

From this study, the ideal candidates for enhanced gas recovery by CO2 injection will be proposed based on simulation results, thus one can screen the available gas reservoirs for CO2 storage purpose and can quickly quantify the additional gas production from the secondary recovery.
Multidiscipline Approach to Real-Time Optimization of Down-Spaced Pay Adds in a Mature Gas Play, San Juan Basin, New Mexico
Authors: Kundert Donald P. , Gangiredla Kaushik , Erdmann Lance , Klem Richard A. , Sanchez Patricio W.
Published: June 2014

As part of an infill pay addition program, 35 wells were selected as candidates for uphole completion in the Gavilan Pictured Cliffs formation in the San Juan basin of New Mexico. The Gavilan is a Cretaceous sandstone body with a stratigraphic trap. Because of the tight well control, multitude of logs and reservoir data, and large discrepancies in initial production potential, it was decided to combine the available data to optimize completion strategies for this program.

A petrophysical study was performed to describe the Pictured Cliffs reservoir for the wells to be recompleted. Wells with complete data were strategically chosen across the area of interest. A fluid saturation model was corroborated with available production data. These wells were then used to generate multivariate relationships to create pseudo results for wells within their respective radii of influence. The resulting porosity, thickness, and saturation values were contoured across the acreage to indicate areas of hydrocarbon and water saturation.

Diagnostic fracture injection tests (DFITs) were used to further describe the reservoir and provide assistance in the hydraulic fracture design. In particular, the DFITs provided general reservoir pore pressure values across the field. Modeled fracture growth in combination with the petrophysical model aided in determining perforation placement to help maximize hydrocarbon production and reduce water production.

The process was ongoing, with changes being made to the pay add completions on a continuous basis. Fracture treatment size and type and placement mechanics were designed for individual wells. Fracturing fluid formulas, pump rates, and proppant types were modified throughout the project.

The result of the program was effective and economical fracture treatment designs of a multilayer tight gas zone. The benefits included optimized fracturing water requirements, as well as proppant amounts and types (i.e., sand vs. low-density proppant). This approach also identified potential areas of interest in the zone for future completion and should lead to reduced operating expenses by avoiding wet zones in the pay. This multidiscipline approach allows an operator in a low-budget environment to use existing well information and previous work programs to help reduce costs and improve well performance. This paper details results, observations, and conclusions that justify this approach.
The North Sea Fiscal Environment - How Governments Incentivize Investment in a Maturing Basin
Authors: Saad Agha
Published: June 2014

There is little commonality of fiscal incentives in the oil and gas sector. This is demonstrated in the North Sea, where rapidly changing market fundamentals had led to a range of fiscal measures aiming to incentivize the sector. Until very recently, rising cost of development against the backdrop of a maturing basin made the North Sea a less attractive place to invest in. Renewed interest in the North Sea seen in the last 5 years has been a direct result of the UK and Norwegian governments engaging with the stakeholders and introducing new policies which have the right incentives to extend basin life. However, in the UKCS, some would argue that these changes have come too late and investment and production levels have been already damaged. A brief review of the challenges in each country, the impact of fiscal incentives and to what extent they have been successful will form the main part of this paper.
Application of Design of Experiment Workflow to the Economic Evaluation of an Unconventional Resource Play
Authors: Chidi Amudo , Xie Jiang , Pivarnik Austin , Pollak Kevin A.
Published: June 2014

The production profile of an unconventional resource play typically has a very steep decline after attaining the peak production rate. Consequently, operators are focused increasingly on drilling the wells faster and getting them on production quicker in order to improve early cash flows. This can sometimes come at the expense of gathering potentially useful data that may help improve reservoir characterization. This practice raises a couple of vital questions that traditional methods based on either deterministic or one-variable-at-a-time (OVAT) methods struggle to answer coherently. Examples of such questions include:

How much impact does drilling and completion speed have on the overall project economic measures? What is the relative significance of all the key factors affecting the project economic measures? Is it worth taking the time to acquire data that can ultimately reduce the uncertainty in the reservoir characterization and production performance? What are the approximate models for the response variables?

A new workflow based on experimental design concepts has been developed to answer the above questions and tested using an unconventional shale oil resource. In this case study, we used the D-Optimal design table and evaluated the impact of a number of diverse factors ranging from speed of drilling, put on production (POP) time, production ramp-up, expenditure, product price to production type curve on the project economic measures. The results, for example, show that while a reduction in drilling and completion times may affect early production metrics, some other factors like production type curve have much more impact on the project's net present value (NPV) and Discounted Profitability Index (DPI).
Disclosures of Resources Other Than Reserves Under Canadian Guidelines
Authors: Etherington J. R. , Chipperfield J. L. , Elliott D. C. , Chan P. B.
Published: June 2014

The importance of improved guidance for the estimation and classification of "Resources other than Reserves" (abbreviated herein as ROTR) has recently been driven by the evolution of the petroleum industry away from maturing conventional accumulations towards unconventional accumulations such as petroleum in ultra-low permeability reservoirs (including shales) and heavy oil/bitumen resources. Commonly these unconventional opportunities involve newer, capital intensive technologies to exploit areally extensive deposits; accordingly, early-stage estimates of in-place petroleum quantities and potentially recoverable volumes may be very large, creating new and critical challenges to communicating clear and consistent information, including the associated uncertainties, relating to resource opportunities. To date, evaluators involved in estimation and reporting of ROTR have had to rely on only limited guidance.

Under Canadian Securities Administrators National Instrument (NI) 51–101 Standards of Disclosure for Oil and Gas Activities, companies are obligated to disclose Proved and Probable Reserves but have the option to additionally disclose Possible Reserves, Contingent Resources and Prospective Resources. NI 51–101 references technical guidelines contained in the Canadian Oil and Gas Evaluation Handbook (COGEH) maintained by the Canadian Chapter of the Society of Petroleum Evaluation Engineers (SPEE). Disclosure of ROTR estimates in Canada has increased substantially in recent years and based on reviews of many filings, is often unclear, inconsistent or potentially misleading. A SPEE Calgary committee has recently proposed additional guidance to promote and improve consistency in the estimation of ROTR for business operations and public disclosure. It is intended to augment other guidelines in COGEH Volumes 1 to 3. Issues addressed with respect to estimation, classification and reporting of ROTR include the following:

Clarification of definitions and principles pertaining to petroleum accumulations, particularly in relation to continuous deposits, Clarification of definitions and principles pertaining to recovery projects and technologies, Exploration and technical and commercial risks, Aggregation of resource estimates. Guidance on reporting the results of ROTR evaluations

Reporting of the results of a resource evaluation under the recommended revised guidelines should provide information for both internal management and external investors sufficient to make informed investment decisions. The revised definitions and classification guidance may be equally applicable in future updates of the Petroleum Resources Management System (PRMS).
The Art and Science of Bidding for Offshore License Blocks
Authors: Danner George E.
Published: June 2014

A company's performance in a lease sale can have serious implications for future growth and sustained value. Therefore it makes sense to approach each sale armed with the most powerful tools available. Surprisingly few firms go beyond spreadsheet analysis when it comes to such an important event, most likely because it is the most familiar method. Perhaps this is why we see bid levels with a significant amount of spread, representing "money left on the table" or skewed perspectives on the value of the block.

Firms that wish to move to the next level take a different view. They choose to engage their best talent in a simulation of lease sales – mythical auctions that are run thousands of times – the collective output yielding insights into the best bid strategies at appropriate levels of risk. While simulation represents the science – setting a bid strategy based upon simulation represents the art. It has been our experience that the top performers in lease sales get the balance of these two dimensions just right.

Building a bid strategy capability using simulation as a centerpiece is challenging, complex work, requiring key data sets and a mastery of the underlying technology simultaneously. That does not mean that best in class bid strategy is not attainable – it comes about with a focus on execution.

We will touch on many of the lessons we learned in working side by side with an aggressive lease sale bidder, and their journey from unsatisfactory auction performance to a place among the top tier of bidders:

Use the talent you already have, but provide the team with an analytical system to translate knowledge into bidder intelligence. Build a serious blueprint of the bidding system before implementation Use the simulations to "steer" the bid strategy

We will focus on the practical, actionable steps to build a better bid strategy through analytics, sustainable across a range of lease sales, both in the US and abroad. As of this writing, Mexico had recently announced plans to conduct auctions on offshore license blocks starting in 2015, and the US BOEM announced a major lease sale each in the Central and Eastern GoM regions scheduled for March 2014.
Reading Between the Lines of A&D Documentation
Authors: Bob Harrison
Published: June 2014

Whenever oil and gas assets are to be divested, the selling company usually provides potential purchasers ("buyers") with their own versions of the following Acquisitions and Divestitures (A&D) documents: a ‘teaser’, a non disclosure agreement (NDA) and an information memorandum (IM).

At the outset of a divestment exercise, sellers often send a flyer or teaser to buyers to garner their interest by conveying just enough of what the deal entails. The language used in the teaser is strident and upbeat in order to whet the buyers' appetite and to encourage them to proceed to the next stage. Then a legally binding NDA or confidentiality agreement or must be signed between buyers and seller, which defines the confidential data to be shared in order that the buyer can understand and evaluate the deal. The NDA forms a confidential relationship between the parties to protect non-public asset information and buyers will not get access to the seller's data room until they have signed one. Finally, the buyers are sent the IM, which contains the pertinent information required by them to make a preliminary assessment of the asset and its value. The IM must grab the attention of the buyers and inform them clearly of the asset for sale while instilling confidence in the buyers of the asset's performance, its management team and its perceived worth.

The paper details the development of each of these documents in turn, explaining what must go into them and what things are better left out. Examples of key elements of each document illustrate how a seller can ensure that his sales pitch stands out from the crowd. These illustrations are also used to give the buyers' point of view and show how investors can ‘read between the lines’ of the A&D documentation in order to formulate searching and critical questions to put to the seller.

One should not underestimate the amount of time and effort needed to produce A&D documentation. Sellers can get external support from brokers, but such help can be expensive and varies enormously in quality, and sellers may have less control over the A&D process.
Restoration of Reservoir Cores to Reservoir Condition before Chemical Flooding Tests
Authors: Rajapaksha Suneth , Britton Chris , McNeil Robert I. , Kim Do Hoon , Unomah Michael , Kulawardana Erandimala , Upamali Nadeeka , Weerasooriya Upali P. , Pope Gary A.
Published: June 2014

Chemical EOR can be a very efficient enhanced oil recovery method when properly designed, but specialized laboratory tests must be done to tailor it to the specific reservoir fluids and mineralogy. The final step in the laboratory evaluation process is to test the chemicals in reservoir cores under reservoir conditions. Unfortunately, available reservoir cores are typically not in their native state. In particular, they are usually in a highly oxidized state (high Eh) compared to the reservoir formation. The oxidation state of the minerals affects the surfactants and polymers used for chemical EOR. In particular, at high Eh some of the iron-containing minerals may have surficial ferric ions that were originally ferrous under the low Eh conditions in the reservoir. Ferric ions can cause polymer degradation, poor polymer transport, and increased surfactant adsorption to the matrix, among other problems contributing to lower oil recovery. In general, to obtain valid test results, such cores must be restored to reservoir conditions to ensure valid results from core floods. We have investigated methods suitable for removing these ferric ions and restoring the core to reservoir condition. The new restoration method described in this paper dramatically improved polymer transport, reduced polymer and surfactant retention, and improved the oil recovery performance by the chemicals in several core floods. It should also be considered for other types of core floods to avoid getting laboratory results that are not representative of the behavior in the actual reservoir, which is in a reduced oxidation state compared to old cores.
Experimentally-Based Empirical Foam Modeling
Authors: Abbaszadeh Maghsood , Nia Korrani Aboulghasem Kazami , Lopez-Salinas Jose Luis , Rodriguez-de la Garza Fernando , Villavicencio Pino Antonio , Hirasaki George
Published: June 2014

This paper presents fine-scale numerical simulations and mathematical analysis of the empirical foam model for representing foam-surfactant flow in a vertical column of laboratory sand-pack based on two sets of experimental data conducted at variable total velocities and variable foam qualities.The empirical foam model of CMG-STASRS is used for parametric matching of laboratory data, and relevant foam parameters are calibrated.The paper discusses experimental setup, procedure and measurements to provide apparent foam viscosity data needed for foam modeling. In the first set of lab tests, foam quality is constant and the total fluid superficial velocity varies for foam shear thinning effect; while in the second tests, foam quality is varied at a fixed total superficial velocity to capture different flow regimes and foam dry-out characteristics.Employing an analytical method and 1-D numerical simulations of the foam flow in the sand-pack, the empirical foam model is tuned to the first data set of variable velocity and used to predict the second data set of variable quality as a consistency check.The model predictions for the second data set as well as the associated sensitivity analysis prove that the foam modeling procedure of this paper is unique and applicable for large-scale predictions.
Use of pH-Responsive Amphiphilic Systems as Displacement Fluids in Enhanced Oil Recovery
Authors: Chen I-Cheng , Yegin Cengiz , Zhang Ming , Akbulut Mustafa
Published: June 2014

We report a novel approach that is based on the complexation and supramolecular assembly of an amino-amide and maleic acid to control viscosity of aqueous displacement fluids. It is shown that the addition of only 2 wt% of adaptable amphiphile/maleic acid into water increases the viscosity of water by a factor of 4.5×105. This superior viscosity behavior is ascribed to the formation and entanglements of layered cylindrical supramolecular assemblies with diameters of several hundred nanometers. Furthermore, the viscosity of the amphiphile solution can be increased 12 times by changing pH from 4 to 8 in a reversible manner. Such a property can be very beneficial for oil-recovery applications when the injectivity becomes a limitation. In addition, the use of switchable viscosity can reduce the energy cost associated with pumping large volumes of viscous displacement fluids. We also demonstrate the proof of concept for the use of adaptable amphiphile solutions in enhanced oil recovery (EOR) as oil-displacement fluids through column experiments. Overall, this study shows that pH-switchable supramolecular assemblies have very intriguing properties that can significantly affect EOR technologies.