bluuebunny/crossref_metadata_2025_split huggingface dataset:
CO2 Injection for Enhanced Gas Recovery
Authors: Kalra Sumeer , Wu Xingru 
Published: June 2014

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Summary
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.
New Art of Building Horizontal and Highly Deviated Wells Help Maximize Recovery and Production from Heavy Oil Fields in Colombia
Authors: Mauricio Patarroyo , Gloria Carvajal , Milena Quintero , Javier Urdaneta , Alberto Gomez , Jaime Pacheco 
Published: June 2014

Abstract
An increasing energy demand combined with the natural decline of old field discoveries has forced oil producers to develop and improve returns from existing assets. In Latin America, many major oil companies have been interested in heavy oils. Higher oil prices and improvements to technology allowing recovery factors up to 30% have made these reservoirs more attractive to operators.
In Colombia, heavy oil fields are being developed in the Magdalena Medio area using steam injection as a thermal recovery method. Cyclic steam stimulation (CSS) is used and consists of three stages: injection, soaking, and production. Steam is first injected into a well for a certain amount of time to heat the oil within the surrounding reservoir to a temperature at which it flows. After sufficient steam has been injected, the steam is usually left to "soak" for a predetermined time period. Finally, oil is produced out of the same well. This process can cause high stress in the wellbore because of the high temperatures used and the cyclical nature of dramatic temperature changes. The elevated temperatures can reach up to 350°C (650°F) during thermal cycling, which, in turn, can potentially cause radial fractures or debonding of the cement, thus potentially compromising the zonal isolation.
Achieving zonal isolation within these shallow vertical and horizontal wells (90° and 2, 200 ft measured depth [MD]/1, 396 ft true vertical depth [TVD]) and avoiding water communication between zones are the primary challenges encountered during these projects. This paper presents a successful methodology, lessons learned, and engineering design changes applied during the past three years to more than 200 wells in the Magdalena Medio area.
Occupational Stress and Hypertension in the Nigerian Oil and Gas Industry
Authors: Umege Declan Chukwuma 
Published: June 2014

AbstractThis study is aimed at comparing occupational stress and hypertension among onshore and offshore engineering professionals in Nigeria for informing regulatory bodies and oil and gas companies, so that recommendation for improvements can be made.Questionnaires were distributed via a two-stage Delphi technique. 104 Engineering professionals responded to the questionnaire. Qualitative and quantitative analysis of the data were carried out with SPSS software.A response rate of 52% was achieved. 90% of the respondents were males and 10% females. Age group responses include 20-29 (6%), 30-39 (44%), 40-49 (46%), 50-59 (4%).80% work on-shore whereas 20% work off-shore. 99% were Nigerians and other nationalities constituted 1%. Identified stress factors were cross tabulated with different demographic factors like age, gender, job location, and department.Result shows that for test of awareness level of occupational stress at α = 0.05, association does not exist between the measures of awareness level of occupational stress and the demographic factors tested.For test of association between stress factors and demographic components, results show that association exists. For test of current methods being employed to manage occupational stress induced hypertension, results shown that no association exists.For test of evaluation of the sources of occupational stress, results show that association exists between stress factors and age, gender and department.Results also show that association exists between the incidence of high blood pressure and job location. On-shore professionals were observed to be more prone than their off-shore counterparts.The present study show that younger engineering professional (age group 30-39) are more at risk of occupational stress than other age groups with males being more at risk than females.This study recommends among other things, discouraging subordinate micromanaging through robust human resources innovations, review of work hours from 8am/5pm to 7am/4pm and establishment of occupational stress committees by oil Companies.