bluuebunny/crossref_metadata_2025 huggingface dataset:
Service Industry & University Collaboration in Teaching Production Optimization with Artificial Lift
Authors: Chokshi R. N. , Lane W. C. , Dunn-Norman S. , Chumkratoke C.
Published: October 2014

As the number of wells utilizing artificial lift continues to grow globally, educating engineers on all forms of artificial lift and production optimization techniques has become essential. Increasing enrollments in petroleum engineering at universities, combined with decreasing availability of experienced manpower in universities and industry pose significant challenges in offering the most current, relevant, and applicable artificial lift content to students.

This paper details the results of a collaborative effort between the service industry and the academe to develop a semester-long curriculum in artificial lift that has right balance of theory, design and application, and which can ultimately be shared among many petroleum engineering programs. The course has been given successfully at one university during the fall term, 2013. In this offering, students learned from practicing, experienced industry technology leaders using traditional in-person as well as and remote teaching methods. The course encouraged collaborative learning through online sessions and practical problem solving using the current software applications. All lectures were recorded for future use and sharing.

Specific insights from the first course offering, i.e. critical elements which made the collaboration and the course successful, are discussed. The paper also provides information regarding plans to expand the course offering to other universities.

This work is important as it confirms the value of collaboration between industry and the academe to support and enhance petroleum engineering education. The work is unique as it details the mechanisms for improved instruction across multiple petroleum engineering programs. The paper also quantifies both the performance of the students and the student perceptions of the course. This effort is consistent with SPE's many recent initiatives to strengthen petroleum engineering education.
A Novel Methodology for Estimation of Multiphase Flow Properties from Sampling Data of Wireline Formation Tester
Authors: Cig Koksal , Ayan Cosan , Kristensen Morten , Mackay Eric , Elbekshi Amer
Published: October 2014

During drilling of a well, the formation is exposed to mud filtrate invasion. The invasion displaces oil in the vicinity of the wellbore, much like a small water flooding experiment in the case of immiscible mud filtrate and formation fluid. Pressure transient or flow test of a wireline formation tester (WFT) commonly provides reservoir properties under the assumption of single-phase flow. However, a WFT sampling operation in a multiphase flow environment gives an opportunity for determining related properties in an inversion workflow by utilizing recorded bottom-hole pressure and water-cut data. In this paper, we present a novel methodology to estimate multiphase flow properties with the help of numerical simulation and optimization.

The numerical simulation model for mud filtrate invasion and cleanup consists of a proper definition of reservoir properties as well as WFT tool geometry, including size and shape of flow inlets, along with tool storage and fluid segregation effects. The model is embedded in an optimization workflow and relative permeability curves, damage skin and depth of mud filtrate invasion are then estimated by minimizing a misfit function between measured and modeled pressures and water-cuts. The relative permeability curves are parameterized using industry accepted models. The optimization workflow uses a distribution function of response parameters where the entire parameter range is included in the numerical runs, thus ensuring that a global optimum is found. Initial parameter estimates for the optimization process are determined from open hole logs, such as resistivity, and from pressure transient analyses.

The methodology developed in this paper is validated by application to a synthetic dataset with a known solution, and it is subsequently demonstrated on actual field data from a sampling job in an oil-water transition zone. The results of this paper demonstrate that it is possible to reliably estimate multiphase flow properties with defined confidence intervals from WFT sampling data. The key contributions of this study are to show the capability of estimating a variety of multiphase flow properties from routine WFT cleanup data and to establish an automated approach, including a novel inversion methodology, to reduce the turnaround time.
Data Acquisition and Processing of Carbon Rod Conveyed DTS and DAS in Very Long Horizontal Wells: First Trial in North Sea Danish Sector
Authors: Danardatu Heru , Gregersen Søren , Altern Eirik , Pellegrini Isabelle
Published: October 2014

This paper describes the planning, execution, data acquisition and processing of Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) conveyed by patented semi-stiff Carbon Rod (CR) in very long horizontal wells. The primary interest in CR starts from its dual nature as a conveyance method and an acquisition tool; it is able to access long horizontal sections and record meaningful flow profiling data. CR presents viable alternative to Coiled Tubing (CT) or tractor conveyed wireline logging tools. When a point pressure and temperature tool is required, it can be conveyed at the end of the CR.

This paper provides information on the preparation and execution of a three wells campaign in the Halfdan field, the first in the North Sea Danish Sector. The CR-conveyed DTS and DAS technology has been successfully and safely tested for the first time in this field. The CR was run in two injector and one producer wells. The campaign has proven the technology advantages and highlighted some learning opportunities. This paper will also describe the processing and visualization of the Temperature and Acoustic profiles and the challenges involved in handling a large volume of data (Terabyte scale).

The semi-stiff CR sensing tool consists of the CR (15 mm in diameter) itself and a bottom-hole assembly (BHA). Embedded in the CR are six optical fibers. Two multi-mode fibers are dedicated to DTS and one single-mode fiber to DAS. The three remaining single-mode fibers are dedicated to Point Pressure, Point Temperature and Vibration measurements. The Fiber Optic (FO) point Pressure (P) and Temperature (T) sensors are located in the BHA. The system provides temperature and acoustic profiles along the rod during the operation. These sensors, in conjunction with surface read out and bottomhole gauge data, provide a comprehensive tool for real-time surveillance and dynamic well analyses.

Although hole conditions were challenging, with the first well exhibiting a great deal of scale that impeded a smooth descent, CR was successfully deployed into the three wells. The rod was pushed into the horizontal sections with a reach performance equivalent to that achievable by equivalent small diameter coiled tubing. The maximum reach of CR was more than 15,400 ft MD, with a record of more than 5,100 ft reach into the horizontal section, without using a well tractor or CT to assist deployment. The sensing campaign produced more than 50 TB of well data.

The interpretation results will be presented in a subsequent publication. The aim of this paper is to serve as a reference in the planning of CR deployed DTS and DAS applied for well and reservoir surveillance.
Production Management Decision Analysis Using AI-Based Proxy Modeling of Reservoir Simulations – A Look-Back Case Study
Authors: Mohaghegh Shahab. D. , Abdulla Fareed
Published: October 2014

Performing look back studies to evaluate the economic and technical impacts of filed management decisions, is not a common occurrence in our industry. Even when such studies are performed, the results are hardly ever published for evaluation and scrutiny by the larger community of industry professionals. This paper presents such a study in the case of a mature giant oil field in the Middle East.

This prolific mature asset that includes more than 160 production wells has been the subject of peripheral water injection for many years to maintain pressure and help displace oil toward the production wells. Production was restricted to 1,500 bbls of fluid per day per well to avoid excessive water production as well as pulling oil from an over produced overlaying prolific reservoir. In 2005 a reservoir management study was commissioned to evaluate the impact of rate relaxation in this asset. The objective was to explore the likelihood of increasing oil production from the asset while minimizing the possibility of increasing the water cut.

The study was performed using the existing, history matched reservoir simulation model. To maximize the utility of the numerical model an AI-Based proxy model called Surrogate Reservoir Model (SRM) was developed and used for the study. Upon completion of the study (during the second quarter of 2005) the SRM ranked all the wells based on the probability of success1, once the rate relaxation program is implemented. In January 2006, management issued permission for the rates in 20 wells to be relaxed.

Using actual field data, this paper reports and evaluates the results and the consequences of the field management decisions, more than five years after their implementation. The approach and methodology used in this project will help reservoir and production managers, engineers and modelers make the most of the tools that are at their disposal to make more informed field management decisions. This paper demonstrates that using the right tools and strategies, skepticism about reservoir simulation models can be addressed effectively and can result in highly successful practices.
Groningen 2nd Phase Compression Project
Authors: Liow E. , Goorhuis H.
Published: October 2014

A Double End Driven Compression train with Active Magnetic Bearings (AMB), a novel concept on its own, has been chosen as the solution for the Groningen 2nd phase compression project. A development assurance program was followed by a team comprising of both Shell and Siemens specialists with the intent of ensuring that technical risks were identified and addressed as far as possible prior to field implementation. A demonstrator compression train has been installed and tested on 1 of the 20 Groningen clusters to allow early operational experience to be gained and verify its reliability. It is currently in its first year of operation and has displayed high availability and reliability.

The paper will describe:

The concept evaluation and selection The creation of the development programme to assess technical risks Technical challenges and learnings Current status of the development and design maturity
The Use Of Reservoir Simulation In Estimating Reserves
Authors: Jones A. D. , Denelle F. R. , Lee W. J. , MacDonald D. G. , Seiller B. J.
Published: October 2014

This paper proposes an approach for assessing a reservoir simulation model for use in estimating reserves. A simulation model can integrate complex static data, the physical description of displacement processes, production constraints and schedules. Hence it can provide important input to business decisions and to reserves estimation. Confidence in simulation predictions depends on the strength of evidence for the input data, quality control of the model, robustness of the history match, and whether there is independent evidence supporting predictions. We explain the principles for evaluating a simulation model and propose requirements for simulation predictions to be considered as proved reserves. This involves evaluation against different strands of evidence e.g. static and dynamic characterisation, wells and facilities description, reservoir performance and analogues. Simulation models are often built to support business decisions using best technical estimates for inputs. There can be instances where a simulation model may be reasonable and reliable but it only represents a‘best technical’ outcome. There may not be sufficient evidence to count the whole predicted recovery as proved reserves. We propose how such a model may be modified to also provide proved reserves estimates. The approach is illustrated through a case study which shows how the principles may be applied with different available data and at different stages of field life.
Multiphase Flow Pattern Recognition in Horizontal and Upward Gas-Liquid Flow Using Support Vector Machine Models
Authors: Li X. , Miskimins J. L. , Sutton R. P. , Hoffman B. T.
Published: October 2014

Multiphase flow occurs in wellbores during the production of oil and gas. Depending on the physical forces and interactions acting on different phases, there can be various phase distributions in the pipes, known as flow patterns or flow regimes, such as bubble flow, slug flow, annular mist flow, and stratified flow. Because multiphase flow pressure gradients change significantly with different flow patterns, the flow pattern prediction is usually the first step before any pressure drop estimation is performed. Moreover, in gas production wells, flow regime prediction can help engineers to determine the continuous phase to deal with liquid loading problems.

Many efforts, including correlation fitting, fluid dynamic calculation, and back-propagation neural network models, have been used to match experimental observations, which are usually presented as flow regime maps. However, there are often mismatches or errors between the prediction results and the experimental data. To avoid such matching errors, this study applies Support Vector Machine (SVM) models to directly represent the measured experimental data. If the assumption is made that there is no error in the experimental data, the SVM models always give correct output results. An SVM model is a mathematical model that is popularly used for pattern classification and nonlinear regression.

For producing oil and gas wells, horizontal and upward multiphase flow is studied in this paper. Experimental data was collected from literature and other sources in order to train the SVM models. Different flow regimes are divided by the boundaries created by the trained models. The model prediction results are plotted in 3-D plots, which provide a clear visualization of how the well inclination angle affects the flow regime transition. The SVM models also perform interpolation approximation to predict the flow regimes at various inclination angles where no experiments have been conducted. Well trained SVM models can be conveniently used and easily combined with pressure loss correlations to calculate pressure drops in wellbores. Finally, an approach using the trained SVM models to deal with liquid loading problems in gas production wells is presented.
Optimization of Well Placement in Real-Time Production Optimization of Intelligent Fields with Use of Local and Global Methods
Authors: Temizel Cenk , Purwar Suryansh , Urrutia Karelis , Abdullayev Azer , Adnan Farashikin Md , Agarwal Amit , Garcia Alejandro , Gorucu S. Emre
Published: October 2014

With recent advances in technology and because of its application in the oil industry, real-time production optimization in intelligent fields has become more practical. The optimal control methods developed previously are now applied in smart workflows to maximize recovery or net present value (NPV). Development of new and mature fields can be improved with integrated workflows that account for the technical and economic aspects of hydrocarbon recovery, as well as the potential impact of uncertainty. This approach is important for a high-impact decision-making process such as well placement.

Optimization of well placement in complex reservoirs requires a thorough understanding of both local and global optimization methods, key parameters, and constraints. A major drawback in this process is that most optimization algorithms are incorrectly understood and applied by the engineers. In this paper, that gap is addressed by presenting not only the theoretical background but also the application of optimization algorithms existing in workflows that couple reservoir simulation with commercial optimization and uncertainty software updated with continuous data flow from the field.

Different optimization techniques are used for optimal well placement. Some of the most commonly used techniques are exploratory, direct, and gradient optimization methods. This paper provides a thorough analysis of these approaches and illustrates the performance evaluations using reservoir simulation case studies as applied in intelligent fields. The analysis considers the computational complexity, scale of the problem, and definition of the objective function. The performance evaluation builds on the analysis to compare the optimal well location, time of convergence to optimal solution, and the corresponding reservoir simulation results. The intended application of this study is to assist in selecting the right approach to make sound engineering decisions for substantial improvement in field production rather than selection of methods which may lead to decreased ultimate recovery.
Predicting Failures from Oilfield Sensor Data using Time Series Shapelets
Authors: Patri Om Prasad , Panangadan Anand V. , Chelmis Charalampos , McKee Randall G. , Prasanna Viktor K.
Published: October 2014

Increasing instrumentation of the modem digital oilfield produces streams of data from sensors that monitor the functioning of different components in the field. This data should be converted to actionable information rapidly in order to respond to events as they happen or are predicted. The challenge is therefore to develop technologies that can process these large sensor datasets rapidly and with minimal manual supervision to ensure a data processing system that can scale with the increasing instrumentation.

We consider as a use-case an oilfield with several Electrical Submersible Pumps (ESPs), each instrumented with sensors that continually measure electrical properties of the pump (the streams of sensor data), which are then relayed to a central location. In this paper, we demonstrate how a time-series analysis approach can be applied to failure detection and failure prediction from the streams of sensor data. The method involves identifying "shapelets" – short instances that are particularly distinct – in the streams of sensor data.

The shapelets approach is particularly applicable to large oil and gas enterprise datasets because the algorithm does not need access to the entire historical data. This greatly reduces the amount of data that needs to be stored for data analysis. Moreover, unlike model-based approaches, shapelet-based analysis does not make any assumptions about the underlying nature of the data, making it practical for applications where a detailed physical model of the pump is not available.

We validate our proposed method by analysis on a representative set of instrumented ESPs. We describe the preprocessing steps that were applied in our analysis. We report the results of experiments to study the effects of varying the data processing parameters on the accuracy of fault detection and prediction. These results indicate that shapelet-based approaches are promising for analysis of time-series data in the oil and gas industry.
The MPD Well Control Matrix: What is Actually Happening
Authors: Rajabi Mehdi Mir , Hannegan Don , Moore Dennis
Published: October 2014

When drilling conventionally, upon indication of an influx, the drill string is lifted off bottom, circulation is stopped, a flow check is performed, and if the well is flowing, the well is shut in. The influx is then circulated out through rig choke using a reduced circulating rate.

With Managed Pressure Drilling (MPD), when kicks occur, they are typically smaller, contained more quickly, and, in some cases, they may be circulated out through MPD equipment without drilling or circulation interruption. The IADC MPD sub-committee has drafted a Well Control Matrix (WCM) in an effort to offer guidelines on when it is acceptable to kill the well dynamically when practicing CBHP MPD.

Rotating Control Devices (RCD) are commonly used on conventional overbalanced mud programs. To many in the industry, no specific distinction is made or special name is given to this type of operation. Confidence acquired over time has encouraged the common practice of drilling ahead while kicks are being circulated out, in appropriate circumstances. An influx, with only a very basic equipment configuration and whether it's called MPD or not, has often been handled in the industry as a routine operation without any special preparation or a formal WCM.

If a WCM is to be required to be in place, it should be engineered properly. A methodology for developing a WCM will be discussed in this paper. Procedures to control influxes as well as how to determine when to revert to secondary well control equipment under these operating conditions and examples of practical applications will be discussed.
Talent Evaluation Paradigms
Authors: Martin Maria Jesus , Jones Deanna , Benson Sharon , Murphy Lynn , Jamaluddin Abul , Nolen-Hoeksema Richard , Hyde Amanda , Chhibber Ravi
Published: October 2014

Access to talent is a growing concern for most E&P companies as the industry focuses on new resource plays, new frontiers, and the adoption of new technologies. The average experience of engineers and geoscientists is decreasing. Consequently, E&P companies are re-assessing the strategic importance of talent development programs to transfer knowledge from experts to recent hires. Current technical talent development models focus on accelerating the development and transferring the domain knowledge, but they often exclude technology proficiency and technology-driven workflows to the developmental detriment of the newly hired engineers or geoscientists. Technology proficiency is essential for finding business solutions in today's data-driven E&P environment.

Using case studies, we compared and contrasted the two different approaches used to develop effectiveness and efficiency of the future petrotechnical experts (PTEs). To develop the effectiveness of PTEs, it is essential to assess their domain knowledge and identify gaps with respect to the capabilities required to execute a company's strategy. In contrast, to develop the efficiency of these PTEs, it is necessary to assess the current technical workflows and the proficiency of the PTEs in using the company's chosen technologies. Four key aspects of training were reviewed: company structure, employee domain knowledge, employed technology, and operational workflows. The assessment results highlight and validate issues that collectively impact the development of PTEs' technology proficiency and productivity.

This holistic evaluation approach ensured that the talent management recommendations were aligned with a company's strategy. Also, this approach highlighted the need for synergy between the human resource department and the senior technical community of the company. The assessment quantified the efficacy of existing talent development programs. Using the established capability and technology consumption gaps, the company was able to focus the investments made in sourcing and/or creating talent development programs.
Drillstring Network 2.0: An Enhanced Drillstring Network Based on 100 Wells of Experience
Authors: Craig Andrew , Adsit Rhys
Published: October 2014

Wired drill pipe (WDP) has been used in more than 100 wells worldwide to create a drillstring network that provides high bandwidth communications between the surface and tools deployed in the wellbore. This network operates independently of drilling fluid, enabling communications for the widest range of drilling applications, including drilling with foamed muds. In addition, the network provides real-time memory/wireline-quality data not only from tools in the bottom hole assembly but also from tools that may be arrayed at intermediate points along the drillstring.

Real-time data like this improves decision making, opens the door for advanced drilling processes such as automated drilling, and gives visibility to downhole conditions where never before possible. Indeed, the numerous deployments in which wired drillpipe has been used have demonstrated that the network provides significant value to the drilling process in terms of drilling safety, efficiency and performance.

Based on the learnings and experience gained across these operations, a new and enhanced version of the drillstring network has been developed. This second generation high-speed drillstring network includes improvements to the design of wired drillpipe, a new generation of distributed network electronics, and a graphical surface network controller. These enhancements and their utility with respect to improving drilling processes are discussed in detail. This paper is an update to SPE-167965 to include the latest field testing results.

These improvements are designed to create a more stable, robust and reliable network system. Further, the enhanced graphical surface controller expands network diagnostic capabilities and reduces the learning curve for network users. Revisions to the wired drillpipe design will result in lower cost of ownership and more cost-effective deployment of the technology, further improving the value the system can provide.
Acid Soluble Plugs – Pressure Tight Solution for a Pre-Perforated Liner
Authors: Livingston E. , Bjornen K. , Burkhead D. W. , Gilbert W. W. , Kent A. W. , Leitch J. , Zhou L.
Published: October 2014

This paper covers the development, laboratory testing, and field testing of Acid Soluble Plug (ASP) technology as a viable completion alternative to wireline or tubing conveyed perforating. The ASPs are installed in a pre-perforated reservoir liner and dissolve when soaked in acid allowing access to the reservoir. This allows the technology to be easily applied in reservoirs where matrix acid jobs or acid fracturing techniques are employed.

The ASP technology was developed to reduce risk and cost associated with wireline and tubing conveyed perforating. ASPs were designed, manufactured, and field tested in both 5 in. and 7-5/8 in. reservoir liner sizes for wells in the Ekofisk and Eldfisk fields. The combination of laboratory testing and large scale field testing influenced the design of the ASPs as well as the additives utilized in the acid systems used to dissolve them. From concept to initial field implementation, the process of ASP engineering development took more than two years.

The concept was initially field tested in deviated injectors with ASPs installed in the deepest section of reservoir liner. The field tests proved the ASP concept prior to depending on the technology in a horizontal producer with an un-cemented, liner-in-liner completion solution. The field tests showed that acid soaking dissolved the ASPs in the down hole environment and allowed efficient acid stimulation of the reservoir. It also reduced the number of wire line runs necessary to complete the well.

When field tested in a liner-in-liner completion application, installation of the ASPs in the reservoir liner eliminated tubing conveyed perforating runs. The reservoir liner was un-cemented with mechanical openhole packers for zonal isolation. The ASPs provided a pressure tight reservoir liner to set the packers against and eliminated fluid loss during the running of the inner completion string.

Optimization of this technology is an ongoing process. The plug design itself continues to evolve as well as the operational steps to minimize the soaking time necessary to dissolve the plugs and gain access to the reservoir. The latest field applications will be shared at the time the paper is presented.
Successful Acidizing Treatment of Four Offshore Wells with High Bottomhole Temperatures in Mobile Bay, Gulf of Mexico: Laboratory and Field Case Studies
Authors: Legemah Magnus U. , Bilden Dean , Lowe Crystal , Gomaa Ahmed , Xiaolan Wang , Qu Qi , Sun Hong , Boles Joel L. , Li Leiming
Published: October 2014

Acidizing high-temperature wells has always been a challenge due to problems associated with corrosion of tubulars and loss of acid carbonate dissolving efficiency. Typical acid treatments of offshore wells with extreme downhole temperatures are carried out using retarded acids, which often degrade, form insoluble salts, and require further neutralization of flowed back spent acid, resulting in loss of production days. Recently there has been a growing interest in using amino-polycarboxylic acids such as glutamic acid, N, N'-diacetic acid (GLDA) to treat carbonate or sandstone formations with high bottomhole temperatures. The benefits of using such acid for high-temperature acidizing are lowered reactivity, inherent chelation chemistry, better tubular protection and biodegradability.

Extensive laboratory testing was conducted before a field trial of the acid. A corrosion test conducted at 395°F using corrosion-resistant G-3 and G-50 coupons (identical to the metallurgy of the tubular) without corrosion inhibitor had a corrosion rate of 0.0068 and 0.0069 lb/ft2, respectively; thus, no corrosion inhibitor was included in the acid used for field treatment. About 2.38 pore volumes of the acid broke through a carbonate core, dissolving 452 mg of calcium at 300°F. A computed tomography scan of the treated core showed a highly branched wormhole distribution network. The acid was found to be compatible with brines and different elastomers often used in downhole completions.

Flowback samples of spent acid analyzed by ICP-OES contained a high amount of dissolved calcium, iron, and magnesium. Further neutralization of the flowed back acid was not required, saving the operator two or more days of production per well.

The successful removal of wellbore scale and formation damage in four offshore wells with bottomhole temperatures ranging from 395 to 410°F with an amino-polycarboxylic acid is presented. Detailed laboratory testing that supported the treatment design and field application will be reported. Production enhancement as a result of the treatments, statistical analysis of flowed back spent acid physico-chemical testing, challenges with the treatment process, and treatment design will also be presented.
Optimizing the Selection of Lateral Re-Entry Wells through Data-Driven Analytics
Authors: Popa Andrei S.
Published: October 2014

A new intelligent model that successfully learns from high-dimensional data and effectively identifies high production areas and optimum Lateral Re-Entry well candidates is presented. The model is entirely data-driven and uses WM rules extraction, fuzzy logic, pattern recognition and Voronoi mapping. We applied our model to a large field with thousands of wells and multiple production layers. We found that it significantly outperforms the previous methodologies, not only by identifying new production areas but also returning a two fold production increase in 2013 compared to prior approach.

The paper showcases a successful project focused on revitalizing poor performing vertical producers by sidetracking and drilling lateral sections into zones with remaining opportunity in order to improve margins and drain reserves more efficiently. The approach uses artificial intelligence technology tools to screen reservoir targets and generate potential candidates. In the first step WM rules extraction algorithms were run for each one of the main reservoir attributes (permeability, thickness, saturation, temperature, etc.) in the nine formations. The results were used to build a fuzzy decision system to generate a confidence index for each grid block in the 155 million cell full field earth model. Confidence index maps were created to pinpoint prime productive areas and help evaluate optimum directional paths. Lastly, Voronoi delineation were used to estimates a drainage area per well, remaining reserves and movable oil in place.

Applying analytics has breathed life into an asset previously thought to have limited growth potential. The future looks bright with a queue of hundreds of well candidates identified and awaiting execution over the next years.
X-ray Backscatter Imaging in an Oil Well
Authors: Spannuth Melissa , Esmaeili Morteza , Gunn Spencer , Ponce-Marquez David M. , Torsteinsen Henning , Voll Adne
Published: October 2014

A new wireline tool that creates X-ray backscatter images of objects within a production well has been developed. Using X-rays to produce images instead of the more conventional optical video recordings offers the significant advantage that the measurement is not hindered by the nature of the production fluid. Therefore, X-ray imaging does not require the well to be specially treated in any way, saving the time and costs associated with cleaning or replacing well fluids.

The tool generates hard X-rays (>10 keV) and measures the backscattered radiation from objects and fluids directly in front of the tool using X-ray detector arrays arranged around the tool axis. Measurements of backscattered radiation are converted into three-dimensional renderings or two-dimensional images of the object using a novel fluid-based surface reconstruction technique.

Example images from operating the tool in a laboratory setting demonstrate the ability of the tool and technique to create reconstructions of objects in a variety of normal production fluids including clean water, saline water, oil, and fluids with suspended rust particles. They reveal the maximum practical imaging depth range from the bottom nose to be approximately 10 cm. The images also demonstrate the millimeter-scale resolution and accuracy of the tool.

The images were produced with a tool exhibiting a commercially viable outer diameter. Thus, this new X-ray imaging method and wireline tool can provide improved visualization and diagnostic capabilities for a significant number of offshore production wells while avoiding the expense and inconvenience of conventional imaging techniques.
Seismic Constrained Reservoir Simulation and Application in a Heavy Oilfield, China
Authors: Cai Yintao , Guo Xiangyu , Ling Yun
Published: October 2014

With the development of reservoir numerical simulation, especially thermal numerical simulation, people start to use thermal numerical simulation model to study the development and distribution of steam chamber in thermal recovery process. But as all known, there still are many uncertainties in the reservoir parameters and well parameters in thermal simulation model, such as the excessive variation of the fluid properties, the uncertainty of static model owing to reservoir heterogeneity and others. These uncertainties usually result in multiple solutions of simulation history matching or ambiguous simulation results.

To reduce multiplicity of history matching in reservoir simulation and better predict the development of steam chamber in the thermal recovery process, seismic constrained reservoir numerical simulation is proposed to incorporate both reservoir simulation and 3D seismic image result in the loop of reservoir simulation and history match. The procedure is discussed through the application to a heavy oil reservoir in which two times of 3D seismic surveys were acquired at the later stage of production, and reservoir numerical simulation was performed in the SAGD (Steam assisted gravity drainage) pilot block of the reservoir.

The proposed procedure includes following main steps: 1) The dynamic data is collected and analyzed for the preparation of reservoir numerical simulation, and an overall distribution of steam chamber is predicted approximately through reservoir engineering analysis; 2) A reservoir simulation model is initially built using available geological, petrophysical and engineering data, and primary history matching is then performed; 3)The reservoir simulation results from previous step and the time-lapse seismic imaging are interpreted comprehensively to find out the consistencies and differences about the steam chamber between them, which are related to history matching errors. 4) Based on these consistencies and differences, the possible factors (geological properties, petrophysical parameters, and rock thermal properties) which caused the history match errors are analyzed, and the corresponding parameters of the simulation model are modified accordingly, and then back to step 2 and 3 for the iteration until a relatively matched result proved by subsequent production data was received.

Application results proved that with the constraint of seismic image data, the reservoir simulation errors can be accurately located and the primary cause for it be determined, and then through reservoir simulation iterations the relatively accurate prediction of steam chamber as well as remaining oil is reached.
North Sea Case Study of an Integrated Sim2Seis Workflow
Authors: Tabatabaei M. , Milovac J. , Bastidas R. , Lau R. , Jameson E.
Published: October 2014

Simulation to Seismic (Sim2Seis) is a forward modeling technique used to predict/generate synthetic seismic response from a static or dynamic reservoir model. There are two key components of a Sim2Seis workflow: reservoir model (geological and/or simulation model) and petro-elastic models (PEMs). PEMs are rock physics functions which relate reservoir properties such as rock types, porosity and fluid saturation to the elastic properties such as compressional and shear velocities, and density. Predicted elastic properties are used to compute reflection coefficients, when convolved with a wavelet generate a synthetic seismic volume (1D or 3D).

There are several applications for Sim2Seis in reservoir characterization. It can be applied to test the consistency of a 3D geological static model, or of a history-matched simulation (dynamic) model with the actual seismic data. It can also be applied to study the impact of saturation change on seismic response (4D effect). A case study from an oil producing Tertiary age field in the North Sea was used to illustrate the applications of Sim2Seis workflow. This case study reveals the value of integrating the static and dynamic data for more accurate reservoir characterization, and consequently building a more reliable reservoir flow model which honors petrophysical and seismic data as well as production data.
Cement Evaluation - A Risky Business
Authors: Benge Glen
Published: October 2014

Cement evaluation is commonly thought of as running a cement bond log (CBL) and attempting to interpret the results to determine if there is isolation in the wellbore. Oftentimes that interpretation is made in isolation with little or no information on what occurred during the drilling and cementing of the well, or the cement systems used. Evaluating cement in older wells where the drilling report states, "ran casing, cemented same" can be particularly challenging.

Cement evaluation is much more than a CBL. Understanding the objectives of the cement job, the design limitations imposed by those objectives and the resulting slurry and job designs are all integral parts of cement evaluation. Oftentimes the selection of a specialty cement system to meet specific well requirements can dictate how the cement can be evaluated.

To properly evaluate a cement sheath, knowledge of the cement job, slurry designs and the limitations of the evaluation technique must be understood. To attempt to perform a cement evaluation based solely on the log output from a CBL, or any log, invites considerable error and bias into the resulting interpretation.

This paper reviews various methods of cement evaluation, from job data, casing and formation pressure testing through sonic and ultrasonic logging. The assumptions associated with each technique are outlined and the discussion includes the limitations of the various techniques along with cautions on how misinterpretation of the results can lead to assumptions of cement integrity that may not be appropriate.

The impact of new boutique cement designs, which incorporate high concentrations of inert materials to give the set cement unique properties, is discussed. The ability of specific logging techniques to evaluate the presence of these slurries is presented. Data on selected boutique cement systems where conventional UCA strength data is not representative of the crush strength of the cement due to the incorporation of specialty materials is included.

An overview of cement evaluation, and a risk based discussion of what technique may be most appropriate based on the cementing objectives is presented. Methods of reducing risk uncertainty in cement evaluation are discussed along with the "validity" of the various data sets available to the engineer to perform a proper cement evaluation on the well.

Understanding the objectives of the cement job sets the boundary conditions for the designs, and from those designs the ability to evaluate the resulting cement placement and well isolation can be determined. Setting the evaluation methodology and understanding the type of information required to apply that methodology can improve the quality of the evaluation.
Industry Guidance for Reporting Environmental, Health and Safety and Social and Economic Factors
Authors: Janus Bertrand , Murphy Helen
Published: October 2014

In 2015 IPIECA, API and OGP will publish the third update of the Oil and gas industry guidelines on voluntary sustainability reporting. Originally published in 2005, with the second edition released in 2010, this guidance document is the principal industry-specific framework for use by oil and gas companies reporting on environmental, health and safety, and social and economic performance. Since 2002, when the development process began, IPIECA, API and OGP have drawn on the very best technical expertise from within the industry to bring precision to indicator definitions and sustainability reporting protocols. This facilitates benchmarking and aggregation of data, enabling greater consistency with the aim of driving performance improvement across the industry.

Now, IPIECA, API and OGP are working on a third update which will revise some of the technical indicators for use in reporting sustainability performance. Industry reporting is continuously progressing and issue areas are not all at the same level of maturity or developing at the same pace. Indicators can evolve based on technical and/or industry developments, and alignment with external reporting frameworks as well as company needs and stakeholder interests.

The Global Reporting Initiative (GRI) produce the most widely used global cross-sector framework for sustainability reports and in 2013 released the fourth version of their guidelines. The updated framework contained a number of disclosures that have a low value-to-cost ratio for oil and gas companies to report against, particularly those related to remuneration and supply chain. Given these developments, it is essential to ensure that the Guidance continues to provide a robust framework for companies in the sector to guide the structure and content of their reports, particularly for new reporting organizations.

The 2015 edition will encompass a number of technical updates including: –providing more detailed guidance on Scope 2 and Scope 3 reporting of greenhouse gas emissions–maturing of specific elements (the Guidance contains three levels of elements: Common Reporting Elements that are well established; Supplemental Reporting Elements that enable greater depth of reporting; and Other Reporting Elements that are less established but emerging.)–update of indicators E6: Freshwater and E9: Discharges to water in light of current industry practices and external developments–possible addition of an indicator on decommissioning

This paper will outline the drivers for maintaining this industry guidance document, the update process undertaken and detail the specific technical updates to the 2015 edition.
Improved Reservoir Description from Pressure Transients
Authors: Tovar Raul
Published: October 2014

This paper describes an innovative approach to integrate pressure transients with numerical reservoir simulation models. The derivative plot, from analytical Pressure Transient Analysis, is used to aid history match pressure transients measurements directly into the production history matched numerical reservoir simulation model. Most often only the extrapolated pressure is explicitly (as a single point measure) incorporated for history matching the reservoir material balance. Characterization of heterogeneity and complex reservoir features such as barriers, and aquifers are subjectively incorporated or inferred in the simulation model from analytical solutions. Furthermore analytical techniques cannot account for all geometrical descriptions and are limited at describing multiphase flow and well interference.

This methodology expands on traditional reservoir simulation history matching by incorporating a stepwise approach in matching geological features on an already built conventional reservoir simulation model. An actual field example is discussed to illustrate on how this methodology populates properties away from the wellbore in terms of grid blocks based on the pressure diffusion regimes of the derivative plot rather than using averaged terms such as the analytical radius of investigation or matching it in a Cartesian plot. It consists of adjusting the simulation model sequentially: wellbore storage, near wellbore permeability (kh and skin), permeability away from the wellbore and boundaries to match the complete spectrum of the observed pressure derivative. Additional field examples illustrate the benefits of this methodology in the context of a multi-well development scenario: The presence of a gas injector that was initially interpreted as a closed boundary and the expected interference response between multiple producing wells.

With this approach an improved description and reduced uncertainty is obtained for the reservoir simulation model, providing a more accurate production forecast to estimate reserves, optimize the reservoir management plan and/or to evaluate additional development scenarios.
Fiber Optic DAS and DTS in Multicluster, Multistage Horizontal Well Fracturing: Interpreting Hydraulic Fracture Initiation and Propagation Through Diagnostics
Authors: Sookprasong P. A. , Hurt R. S. , Gill C. C. , LaFollette R. F.
Published: October 2014

The application of high-resolution fiber optic distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) during multistage hydraulic fracturing has increased in recent years. However, fiber optic has been used for communication networks, surveillance, and monitoring and diagnosing wellbore integrity for quite some time. The technology has also been used to diagnose reservoir and well performance, e.g., production and injection profiling.

Optical fibers were placed in a small stainless steel tube, which was clamped to the casing while running in the hole in a horizontal unconventional gas well. The casing was then cemented in place, and fracturing treatments were completed by limited-entry techniques using the "plug & perf" process, resulting in multicluster (each stage), multistage fractures. Perforations were placed on the topside of the casing, oriented to avoid damaging the optical fiber (zero degree phasing, at 5 shots per foot, one foot per cluster).

This paper shares images and results from DAS and DTS data that allow for interpretation of fracturing treatments in multicluster, multistage horizontal wells. The images illustrate the dynamic nature of the spatial and temporal fluid distribution pertaining to initiation, propagation and arrest of hydraulic fractures during simultaneous stimulation of multiple clusters. First, fracture initiation appears not only during early time, as expected, but also late time initiation events may develop in previously dormant clusters. Second, propagation of multiple fractures can occur randomly within a cluster array, and these multiple fractures are sometimes in close proximity to one another. Third, dominant clusters are often observed during stimulation. Further, during the treatment cycle, the position of dominant cluster(s), within a given stage, may actually change. We leverage these observations with various other data sources in a modeling exercise to demonstrate the implications of unequal fracturing fluid distributions on propped fracture performance.