bluuebunny/crossref_metadata_2025 huggingface dataset:
The Convergence of Knowledge Management, Collaboration, and Enterprise Social Computing in the New Learning Organization
Authors: Holloway Sandra
Published: June 2014

Broad industry trends that are reshaping the exploration and production operation—an aging work force, competition for the best talent, generational shift, and increasing business complexity—warrant a rethinking of traditional operating models as part of new digital oil field strategies. New operating models, based on collaborative business processes and specialized operating facilities, link engineers with platforms and fields in remote locations via real-time global networks. These collaborative environments enable energy companies to leverage the collective knowledge and experience of expert practitioners to improve performance and capture maximum benefits from smart oil field technologies. Important capabilities that contribute to the success of new operating models include the operator's ability to shape a new culture of collaboration and teamwork based on trust and knowledge transparency, propagate global communities of expert practitioners, leverage tools and technologies that enable the capture and sharing of knowledge in real-time, and, integrate continuous learning as a strategic organizational capability. Now, next-generation Internet, collaboration and knowledge-sharing technologies are converging to introduce a new class of user-defined, user-driven applications that hold the potential to speed realization of these capabilities across the digital oil field. This paper explores how energy companies can leverage next-generation knowledge management; enterprise social computing; and collaboration technologies, as an integral part of digital oil field information systems, to enhance collaborative decision-making and knowledge sharing; and drive operational excellence.
The Value of Data in Multiple Repositories
Authors: Kozman Jess
Published: June 2014

Recent mergers and acquisitions have produced a trend of selecting "best of breed" applications for exploration and production analysis. The prevailing opinion is that reducing the number of applications and their associated data repositories leads to savings in data management costs. However, an analysis of the actual impact of these shifts in terms of Change Trajectory, as defined by industry studies on threats to core activities and assets, shows that the cost of data transition and change management may outweigh and these advantages. A standard methodology for identifying and analyzing the data repositories and processes used for business critical exploration and production data types shows that there is an optimum complexity of data management infrastructure for any given size organization. The impact of data management processes is measured by value statements created from standardized measures of opportunity cost. Multiple international case studies are used to document a direct relationship between the complexity of data management repositories and processes and the maturity of data management solutions, as measured by an industry standard Maturity Model. These case studies illustrate different Change Trajectories of oil and gas producers and the information management services industry, using examples of client environments where data has been migrated between applications. Analysis of these migrations suggests a roadmap for success in adopting the correct Change Trajectory strategy. Organizations that fail to recognize the correct strategy will lose considerable competitive advantage during the merger and acquisition cycle.
Safety in the Digital Oilfield: A System Integrator's View
Authors: Lasrado Vineet
Published: June 2014

This paper covers different aspects of safe operations and steps organizations can take to use information technology solutions to improve the safety of their operations. Safety alerts, Information management for availability of latest documents and data, safety KPIs and integration of KPIs from different systems, GIS to track a potentially hazardous situation, Maintenance systems are examples of IT solutions for improving the safety of operations. It is also important to integrate multiple systems in order to improve workflow and reduce scope for error due to manual processes. The importance of sharing data on safety and how IT solutions can be used to share data across organizations (via a third party) will be addressed. Several different organizations where incident information is maintained will be mentioned.

Safety of operations is an important aspect of HSSE in the oil and gas industry. Several steps which organizations can take to improve safety will be discussed. These steps help in making data easily available and reducing the time spent in incorporation of Integrity Management programs. Typical results of the impact of certain IT solutions in this paper on safe operations will be discussed (the results are from the literature and not of any study conducted for this paper)

IT Solutions can help in improving safety in the digital oilfield. A variety of solutions to increase the safety of their operations via IT solutions exist. An overall assessment and proper project management of any newly designed system is also required to find any new risks due to the implemented systems as compared with the previous mode of working. Change management is also an extremely important aspect to make any new solution to be adopted successfully in the organization. One of the KPIs has to be to improve the safety of the operations.
Hydrates: State of the Art Inside and Outside Flowlines
Authors: Sloan E.D. , Koh C.A. , Sum A.K. , Ballard A.L. , Shoup G.J. , McMullen N. , Creek J.L. , Palermo T.
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

The state of the art of three hydrate applications in petroleum engineering is presented in order of decreasing importance:flow assurance,energy resource, andclimate change. In flow assurance, there is a hydrate-plug-prevention shift under way: from avoidance to management of hydrate formation.

In addition to avoiding the region of hydrate stability by injecting thermodynamic inhibitors, time-dependent studies enable flow-assurance engineers to better address such concerns as flowline restarts, cold (stabilized) flow, low-dosage hydrate inhibitors, and plug remediation. These applications are related to conceptual ideas of hydrate-plug formation in oil and condensate systems. The second area, energy resources, is marked by a transition to an extended production test in the permafrost, and to characterizing resources and economics in the marine environment. The third area, climate change caused by hydrates, is an area of current research. Preliminary estimates suggest no abrupt methane contribution to the environment from hydrates in the immediate future.

Introduction

Natural-gas hydrates (clathrates) are crystalline, ice-like solids that form when small (<9 Å) molecules contact water at low temperature and high pressure (Sloan and Koh 2008). Because hydrates are solids, they can block oil and gas flowlines; flow assurance involves considerable effort and expense to ensure that this blockage does not happen. Also, hydrates concentrate hydrocarbon gases by a volumetric factor of 164 (at standard temperature/pressure), such that large deposits of natural hydrates are becoming factors in energy resources and climate concerns in marine and permafrost deposits.

A combination of applications, principally in flow assurance, energy, and, more recently, climate change, has driven hydrate engineering and science for 75 years. The number of published hydrate-related papers is an exponential function of time, extrapolating to more than two refereed publications per day in this decade. As Table 1 summarizes, triennial international hydrate conferences have been held since 1993; the most recent conference, in July 2008, presented more than 400 manuscripts.
The Role of Gas Processing in the Natural-Gas Value Chain
Authors: Hubbard Robert
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Production of natural gas is the first step in the value chain that takes gas from the reservoir to the customer (typically at a burner-tip). An integral and essential part of this value chain is the midstream sector. Midstream refers to the gathering, compression, and processing functions required between the wellhead and the transmission system.

Midstream assets and activities are found at any location where natural gas is produced, transported, or sold. For example, in North America the first gas-gathering and -processing facilities were installed circa 1910, primarily to extract casinghead gasoline from solution gas produced with crude oil. In Europe, the midstream sector developed in the 1960s with the discovery of large nonassociated-gas fields in the southern North Sea and in the Groningen field in The Netherlands. Industry development in the Middle East was spurred by the huge associated-gas-gathering and -processing projects initiated by Saudi Aramco in the late 1970s and early 1980s. Fig. 1 shows a schematic of the gas-gathering and -processing facilities in the total production system. This article discusses the gas-processing portion of the midstream sector, with the primary objective of providing technical professionals on the upstream side of the industry some insight into the midstream sector.

Gas Conditioning and Sales-Gas Specifications

One of the principal objectives of the gas-processing industry is to condition the gas for sale. Natural gas must meet several specifications before it can enter the transmission system. Historically, these specifications have been referred to as "sales-gas specifications," but in many areas they are really transportation specifications. This is because gas from many producers will be transported in "open-access" gas pipelines to the gas buyers along the pipe route. The sales agreement may be between the producer and the buyer, but there is no guarantee the buyer will actually receive the producer's molecules. In North America, for example, producers negotiate transportation agreements with pipelines and must meet the shipper's transportation specifications before the pipeline operator will accept the gas. These specifications are set out in the tariff the shipper files with the US Federal Energy Regulatory Commission. Table 1 shows some example sales/ transportation specifications in North America and Europe.
Challenges of Gas Well Completions: Recent SPDC Experience
Authors: Nnanna Erasmus , Ekeigwe Augustine , Alaka Collins , Owolabi Segun
Published: June 2014

Increase in both export and domestic gas demand has led to increase in the development of high rate gas wells by the Shell Petroleum Development Company of Nigeria (SPDC). Ability to deliver at expected potential and ensure integrity is a very critical factor to guarantee sustained gas supply and safeguard contractual obligations.

In the light of this, over the last five years, different operational challenges such as the inability to deploy sand screen across target intervals, parting of screens during deployment and casing deployment shallower than planned setting depth have been experienced.

This paper highlights some of the challenges encountered during the completion of these wells and the recovery strategies adopted that led to the successful implementation culminating in minimal loss in well potential and access to developed reserves.
Results of Gas Injection in the Cedar Lake Field
Authors: Leibrock R.M. , Hiltz R.G. , Huzarevich J.E.
Published: June 2014

The various factors considered in recommending the initiation of a gas injection project in the southern portion of the Cedar Lake Field are discussed. Performance history under gas injection operations is reviewed and these data are analyzed, utilizing both the material balance method and the fractional flow and frontal advance expressions.

Results of the analysis of the performance data indicate that the injected gas has contacted and affected at least 60 per cent of the reservoir and a substantial increase in ultimate recovery can reasonably be expected. By holding the reservoir pressure appreciably above the bubble point, the well productive capacities have been maintained substantially above the level predicted for primary operations.

The analysis of the Cedar Lake project suggests that in certain limestone reservoirs, at least, the probable success of gas injection cannot be predicted simply from observation of permeability distribution throughout the pay section, as indicated by core analysis data, on either one or a number of wells. Further, the performance of this particular project fails to indicate any basis for classifying carbonate reservoirs in general as being inherently unsuited to a dispersed type gas injection program, thus indicating that each reservoir should be considered on its own merits, regardless of the composition of the reservoir rock.

Introduction

Early in the life of the Cedar Lake Field, an extensive data gathering program was initiated to provide an accurate record of reservoir performance characteristics. From the study of these data it was apparent that there was a critical need for supplementing the natural reservoir energy in order to maintain well productivities and obtain the maximum ultimate oil recovery. Accordingly, detailed engineering studies were made of the various methods of secondary recovery which might be applicable. As a result of these investigations, the decision was made to initiate a gas injection program of sufficient intensity to maintain reservoir pressure at approximately 600 psia, or some 274 lb above the bubble point pressure of 326 psia.
Numerical Simulation of Wellbore Dynamics During Underbalanced Perforation
Authors: Bahrami H. , Siavoshi J. , Veisi M. Sheikh , Bahraie R.
Published: June 2014

The main objective of perforating is to connect the wellbore to the reservoir zone by creating tunnels through casing and damaged zone into the undamaged rock. The process of detonating perforation charges generally causes damage due to crushed rock material around the perforation tunnels.

There are different methods used to mitigate damage due to perforation, such as static and dynamic underbalanced perforation. In static underbalanced perforation, conventional high shot density perforating guns are run in underbalanced conditions in order to have clean-up after perforation. In dynamic underbalanced perforation, a specific gun design associated with gun puncher charges provides dynamic underbalanced conditions across the perforated interval immediately following charge detonation in order to efficiently clean up each single perforation tunnel from crashed rocks and debris.

Using deep penetrating charges followed by a dynamic underbalanced can improve well productivity since it mitigates the damage related to perforation. Dynamic underbalanced perforation removes the crushed rocks and debris from the tunnels using a sudden pressure drawdown across the perforated interval immediately after detonating the charges.

This study is intended to numerically simulate the dynamic underbalanced conditions after perforation in order to have a better understanding about the phenomenon during perforation process as well as perforation cleanup. The effect of wellbore fluid type on dynamic underbalanced behavior has been simulated to investigate efficiency of dynamic underbalanced in different wellbore conditions, and also three field examples are also shown to verify the simulation results.
Streamline Simulation with Compressibility and Spatial and Dynamic Variation in Oil Composition
Authors: Beraldo Valcir Tadeu
Published: June 2014

There are several oil fields offshore Brazil with horizontal oil density variations. API tracking, that is available in some commercial finite difference simulators, can deal with such cases by allowing definition of an initial oil gravity distribution and tracking variations of oil density, due to the movement of oil.

Streamline-based simulators can be much faster than conventional finite difference simulators when applied to large and heterogeneous models. However, this approach is most accurate and efficient when it is assumed that the rock and fluids are incompressible. In previous work (Beraldo et al, 2007), an incompressible formulation for streamline simulation with an API Tracking option using two components in the oleic phase was presented.

This paper presents a compressible formulation for streamlines that also considers API tracking. It extends the work of Cheng et al. (2006) and Osako and Datta-Gupta (2007) by consistently accounting for flux of mass and volume along streamlines. It was described how mass and volume can be mapped between the underlying grid and streamlines to minimize mass balance errors and how consideration of cumulative volume in a streamline can substitute for time-of-flight (Beraldo 2008).

The method was implemented in a three-dimensional two-phase streamline-based simulator. Tests based on a Brazilian oilfield model and on the SPE10th Comparative Case demonstrate that the implementation can reproduce the results of a conventional simulator, while being substantially faster for finely-resolved models, even when compressibility is significant.
Brunei Shell Petroleum Champion Field Gas-lift Optimization Project – FieldWare Production Universe Implementation in a Brown Field
Authors: Wee Thierry , Turco Agostino , McIlroy Roger , de Boer Frank , Cramer Ronald , Dolan Michael J.
Published: June 2014

Brunei Shell Petroleum (BSP) is undergoing a significant modernization of its gas-lift system in the Champion field in Brunei. With smart gas-lift flow control valves, BSP is continuously controlling the gas for gas lifted wells on remote, unmanned production facilities. Shell Global Solutions is assisting this process by the implementation of the FieldWare* Real-time Optimization (RTO) system. This system, which uses data driven models to optimize production, has already proven its value in this field during a prior pilot installation. The successful implementation of BSP Champion field gas-lift optimization is an example of the significant value that Smart Fields* implementation brings to a brown field. As a result Gas-lift efficiency has been sustainably increased by 40% in one of the implemented platforms. This paper discusses the RTO project execution, technology involved, the implementation process, its results and finally the business benefits achieved.
New Technique for Addressing SIMOPS Challenges During Installation of New Offshore Platform
Authors: Ataya Zaher M.
Published: June 2014

SIMOPS stands for simultaneous or concurrent operations, which present serious potential HSE and operational risks as it, combine the hazards and risks of drilling and production or production and construction or drilling and construction and or drilling, production and construction (TRIOPS). Shutting down any operation for conducting the other one(s), may not be easy, feasible and or cost efficient decision. The current paper focuses on a new technique and method for addressing SIMOPS risks and challenges, especially during the installation of new offshore gas injection platform in close position to the existing super complex (production station), and sub sea pipe lines. The study sets good practices and standards that can be used by other offshore oil and gas companies to reduce SIMOPS risks to as low as reasonably practicable (ALARP) level.
Effect of Formation Stress Distribution on Hydraulic Fracture Reorientation in Tight Gas Sands
Authors: Aghighi M. A. , Rahman S. S. , Rahman M. M.
Published: June 2014

Initial period of production from a fracture stimulated tight gas sands can alter stress distribution around the hydraulic fracture. This allows a new fracture to reorient along a different azimuth, even up to 90 degrees, thereby providing access to less depleted zones and retrieving productivity. Success of hydraulic fracture re-stimulation significantly depends on the stress state of the wellbore adjacent area. Using a finite element based fully coupled poroelastic numerical model which includes wellbore, poroelastic formation, a pair of finite conductive fracture and refracture, this paper examines the effect of production induced stress perturbation on the initiation and orientation of a secondary fracture in hydraulically fractured tight gas reservoirs. Results of this study have shown that the area of stress reorientation around a producing hydraulically fractured well is constrained by two distinct planes. By simulating wellbore re-pressurization, it has been also shown that such stress distribution, which is induced by initial production period, can lead to further propagation of the primary hydraulic fracture instead of reorientation of hydraulic fracture. Furthermore, it has been also observed that properly oriented perforation prior to refracture treatment and/or existence of micro-fractures at the wellbore wall can facilitate refracture reorientation before the primary hydraulic fracture starts propagating.
Revamping Old Fields Using I-Field Technologies
Authors: Al-Khamis Mohammed N. , Al-Hamzani Housam J. , Al-Adel Mahdi F.
Published: June 2014

With the ever growing demand for energy in the world, the need for timely and accurate data from oil fields to allow proper decision making becomes very crucial. Recent evolution in oil field technologies has made a great revolution in the oil and gas industry all over the world, leading to the emerging development of intelligent fields (I-Fields)1–4. The integration of I-Field technologies, whether downhole or at surface, coupled with communication networks along with sophisticated simulation and monitoring applications has led to significant advancements not only in monitoring and control capabilities, but rather also in decision making processes5. Therefore, the overall system upgrade has resulted in an enhancement of the field surveillance, which will lead to higher levels of oil production in these assets as a consequence of Saudi Aramco's development strategy for these fields.

Three previously produced oil fields that were mothballed were revitalized and redeveloped after extensive drilling and workover programs. The latest downhole production technologies were installed in all oil production and water injection wells. Furthermore the project called for the construction of new oil and gas processing and water injection facilities, all linked to their respective wells via an elaborate fiber optic communication network for optimum control and surveillance capabilities in real time mode. The production and injection strategies were further optimized making use of I-Field components, such as Permanent Downhole Monitoring Systems (PDHMS), Smart Well Completion Systems, Multiphase Flow Meters (MPFM), Single Phase Flow Meters, pressure and temperature sensors with specially tailored monitoring, and simulation software.

This paper will describe how the installed and applied I-Field technologies in these three fields have allowed better data management, helped in optimizing the production and injection and overall has enhanced the operation and safety of the field operations. Moreover, several examples will be discussed showing the benefits of real-time surveillance in optimizing the fields’ performance with a special focus on the use of monitoring and simulation tools to more accurately mimic the current performance of the wells, and consequently used to generate optimized production and injection scenarios.
Improving Allocation and Hydrocarbon Accounting Accuracy Using New Techniques
Authors: Cramer Ron , Schotanus Dave , Ibrahim Kolin , Colbeck Nick
Published: June 2014

In the oil industry, it is necessary to reconcile fiscally measured hydrocarbon production with estimated production from associated wells. This process is known as "allocation" and is important for a number of reasons, including accounting for field production to owners/governments, field surveillance, and volumetric input to reservoir simulators.

Traditionally, allocation is performed on a monthly basis, reconciling the "less-accurate" sum of the well tests adjusted by well uptimes with the "more-accurate" fiscal measurements. This process is subject to a number of inherent inaccuracies, including less-than-perfect well tests, lack of knowledge of precisely when the wells were interrupted, unknown well-flow changes, and uncertainty as to how to allocate effectively the difference between fiscal and well-test measurements.

Ineffective allocation can lead to financial consequences caused by inaccuracies in volumes allocated between various owners and tax regimes. Inaccuracies can also feed through to reservoir simulators, which may be used in corresponding decision-making processes (e.g., where to drill the next well). These inaccuracies are generally compounded with time because allocation is performed month after month throughout the field life cycle.

Associated with hydrocarbon accounting are key performance indicators (KPIs) (e.g., well daily production and deferment rates).

The purpose of this paper is to describe Shell's experiences in improving allocation accuracy and automatic KPI reporting through more-effective use of available production data and by using a continuous, rather than a discontinuous, hydrocarbon accounting process.
Nimr Water Treatment Project - Up Scaling A Reed Bed Trail To Industrial
Authors: Breuer Roman , Al-Asmi Said Rashid
Published: June 2014

The Nimr Water Treatment Project is to develop and set up an effective water treatment plant for the residual waters produced from the Petroleum Development Oman (PDO) oil wells in its Nimr Oil Field with a capacity to process a minimum of 45,000 m³/day produced water.

PDO initially established a pilot project 10 years ago in the Nimr Oilfied in the Sultanate of Oman; see Figure 1 Map of Omani Oilfields – The Nimr Cluster. The technology used was based on a constructed wetland followed by an evaporation pond to remove the produced water contaminants and reduce the effluent. Using the experience of the pilot a Design, Build, Own, Operate and Transfer (DBOOT) tender process was started to upscale the pilot from a capacity of 1,000 m³/d to 45,000 m³/d in 2007. The project was awarded late in 2008 and based on PDO and the contractor's experience one of the biggest commercial constructed wetlands is build for water treatment.

Main technology changes were made based on pilot test results, an extended study of the water characteristics and climate data. The result is the construction of an approximately 600 ha large facility comprising of an Oil/Water Separator to recover remaining crude oil, a surface flow Constructed Wetland and finally an engineered salt works facility to include the option for salt recovery. Additionally, potential benefits of biomass utilisation and carbon credit values are investigated to be potentially included into the project after commissioning. Construction works have commenced in May 2009 and water is bound to flow in January 2011.
Reducing the Carbon Footprint of Drilling and Completion Operations
Authors: Gilbert Y. , Hagström M. , Getliff J. M.
Published: June 2014

The use of planning tools to minimize waste and discharges to the environment during well construction is fast becoming the norm in the oil and gas industry. Air emission control through the same approach is also desirable. Calculating the carbon footprint of a well construction operation is however usually done after the event. When planning the well, air emissions are generally taken into account through qualitative evaluations, and consideration of emissions from disposal activities appears to be somewhat rare. Nevertheless there is a clear advantage in a quantitative analysis of the operation, as it supports emission mitigation at source and allows the engineer to compare different operational choices.

The objective of the development work undertaken was to create a user-friendly yet scientifically defensible methodology for calculation of greenhouse gas (GHG) emissions, air pollutants, fuel consumption and fuel costs before well construction takes place. The aim was to enable engineers to compare different operational choices in a quantitative manner. The developed methodology utilises databases of equipment, specific energy consumption and specific emission factors and allows pre- operational calculations without the need for detailed data on actual power consumption or fuel use. This allows targeted emission mitigation to be incorporated into the planning stage.

The initial phase of the project included a review of GHG calculation methodologies and the air emission reporting requirements in the EU and the USA. Existing methodologies appear to have been designed to support post-operational calculations, where accurate data on fuel consumption and fuel consistency is known, thus some methodology development was required as such data is not available before an operation.

The approach used in this calculator takes into account all aspects of the operation that can be influenced by the operator: Logistics, equipment, fluid choices and waste management options, including different end disposal options. The results include both detailed breakdowns and rapid overviews of emission sources both for greenhouse gases and the traditional air pollutants. Applying the concepts developed in the planning stage supports identification of best practices and allows targeted improvement efforts towards areas of greater emissions. The actual tool can be used for both comparisons during the design stage and as an aid to audits for accurate post-operational emissions audits.
Production Processes Integration for Large Gas Basin – Burgos Asset
Authors: Sandoval G. , Martínez F. , Cadena A. , Bernal H. , Vega E. De , Navarro M. , García M. , Leal I. , Figón L. , Zambrano A. , Duran J. , García M. , Rangel M deL. , Garza E. , Corbellini F. , Mota M. , Escalona H. , Aguilar Y. , Corona A. , Oca A. Montes , Tortolero M. , Díaz T. , Álvarez N. , Montes E. , Romero E. , Suárez A. , Romay J. , Fuehrer F. , Kinani A. Al , Holy R. , Núñez G. , Vernus J.
Published: June 2014

This paper presents the advances in Production System Optimization for the largest gas field in Mexico. The Burgos Asset is a large gas brown field with reservoir characteristics like gas-loading backpressure, reduced permeability and tight gas formations where production declines rapidly. Due to the large number of wells (more than 3500 active wells) and the fact that 95% of the measured parameters are obtained by field operators, it is difficult to continuously monitor and to plan the usage of operational resources.

To help solve this situation, PEMEX and the service company (Schlumberger) implemented a production surveillance system that gathers all operational information providing storage, quality control, and developed engineering processes to estimate gas rates and liquid loading, monitors KPI and detects anomalies in operational events.

Implementation of this operational surveillance environment started in 2007, with a functionality that has been focused on monitoring KPI calculation and event analysis at well level. Due to the large number of wells and activities carried out by the Asset, the need arose to generate additional workflows that contribute to the production optimization process, candidate selection workflow for workover and artificial lift installation, allowing upscaling of the current solution to a level that supports the technical and economical decisions of the Asset.

As part of this requirement the team took the initiative to incorporate workflows of candidate recognition for workover, de-bottlenecking and optimization of a particular set of facilities, allowing the Asset to take corrective action in these areas and to plan the recommendations accordingly. Additionally, as proof of concept, an intelligent candidate selection system was implemented for artificial lift installation opportunities, using artificial intelligence tools such as data mining, improving decisions and results.

The initiatives mentioned above help to increase, validate and rank the Asset's diverse candidate basket and to integrate the economic constraints into the decision making process. The positive results that have been obtained in these focalized areas show a significant opportunity to be up scaled for the whole Asset.
ES-SAGD; Past, Present and Future
Authors: Orr Bryan
Published: June 2014

North America's long-term energy future depends heavily upon the Athabasca oilsands. Only 15% of these deposits are at mineable depths (<90m) and thus 85% of the oilsands (232 billion bbl recoverable reserves) must be recovered using in-situ techniques. Steam Assisted Gravity Drainage (SAGD) has become the method of choice for oilsand producers and it is therefore critical to optimize this process.

ES-SAGD or expanding solvent steam assisted gravity drainage involves the co-injection of a hydrocarbon solvent and steam to improve recovery from the SAGD process. The hydrocarbon solvent is soluble in bitumen at reservoir conditions and serves to decrease its viscosity thereby increasing the production rate over a process driven solely by steam.

This paper investigates several ES-SAGD pilot projects with a focus on the Nexen-OPTI ES-SAGD project at Long Lake. Additionally, a literature search was performed and the data, found in public ES-SAGD papers on steam-solvent labs and simulation studies, is summarized. Nexen is also currently involved in a lab experiment being operated by AGAT involving a comparison of the performance of different hydrocarbon solvents for assisting the SAGD process.

ES-SAGD should be pursued because successful implementation would significantly improve profitability by accelerating production, decreasing water losses and decreasing steam requirements. Additionally this will address environmental concerns by decreasing CO2 emissions. ES-SAGD will also increase reserves both per well pair and on a total oilsands basis.
Application of Nanoparticle Saturated Injectant Gases for EOR of Heavy Oils
Authors: Shah Rusheet D.
Published: June 2014

Heavy oil is an immense oil resource that is untapped because its highly viscous nature makes it difficult to produce. Currently, the heavy oil reservoir production challenges are addressed by thermal recovery techniques, CHOPS, chemical injection and miscible gas injection. In this work, the advantages of three different processes viz thermal, chemical and miscible gas injection have been merged together to come up with a novel viscosity reducing process for heavy oil. Metal Nanoparticles are used for thermal conductivity enhancement of super critical-CO2 (sc-CO2) or "Viscosity reducing Injectant" (VRI) for reducing the viscosity of heavy oil rapidly as compared to conventional sc-CO2 or VRI. A sc-CO2 soluble surfactant has also been added to the mixture to further enhance the viscosity reduction. Thus the thermal properties of metal nanoparticles, the chemical properties of surfactant and the miscible properties of sc-CO2 and VRI altogether reduce the viscosity of heavy oil.
Managed Pressure Drilling Avoids Losses while Improving Drilling and ECD Management in the Gulf of Thailand
Authors: Fredericks Paul , Garcia Greg , Sehsah Ossama
Published: June 2014

A number of oil fields in the Gulf of Thailand are characterized by severely depleted gas sands and unstable coal and shale. Operators drilling high angle and horizontal wells in those fields often have to contend with problems associated with high equivalent circulating density (ECD) and the narrow operating margin between fracture gradient and borehole stability.

Reaching total depth in those fields without losing returns is possible but it requires careful management of the ECD, vigilant hole cleaning practices, and controlled drilling. Unfortunately, success comes at the expense of drill time which is unavoidably reduced by those same conventional practices.

Automated Managed Pressure Drilling (MPD) was a solution used by one operator to improve drilling efficiency while still avoiding losses and maintaining wellbore stability. By taking advantage of the MPD system’s ability to manage the BHP when the mud pumps are off the operator was able to reduce the static mud weight below wellbore stability and the ECD below the fracture gradient. With the reduction in mud weight the operator was also able to change the mud rheology in other ways that contributed to improved hole cleaning.

Managed Pressure Drilling was initially used in a three well program in 2007 and later in an extended six well program in 2009. For most of the wells the drilling plan was the same: conventionally drill out of the 9–5/8” casing with an 8–1/2” bit down to the top of the depleted zones, lighten the mud density and rheology, bring the MPD system on line and drill through the depleted zone to the next casing point. However, midway through the second program the well plans changed and MPD was used to drill the entire 8–1/2” section.

For all nine wells, the MPD system remained the same: a dynamic pressure control system with an integrated real-time hydraulics model, an automated manifold and backpressure pump, and early kick detection equipment. Even though the trajectory changed from well to well, surface and downhole conditions remained relatively constant in terms of borehole and drill string geometry, stratigraphic sequence, mud rheology, drilling practices, MPD system, and rig type.

Such relatively constant conditions created favorable circumstances for the comparison of conventional and MPD practices. Results show that MPD enabled the operator to avoid losses and achieve noticeable improvements in drilling efficiency and ECD management. In addition, there were noticeable improvements in MPD performance in terms of transition times and BHP control.
Applications of Bio-enzymatic Completion Fluid in the Tight Sand Gas Reservoirs of Ordos Daniudi Gas Field
Authors: Qiang Lan , Gongrang Li , Jinghui Zhang , Haibin Li , Liping Wang
Published: June 2014

At present, Ordos Daniudi gas field is developed with the gas of Shan-1 and He-1 reservoirs, whose lithologies mainly are tight sands. The reservoirs have severely potential formation damages, induced by mechanisms such as strong water-sensitivity, water-blocking and solid slugging with small particles. The solid-free brine completion fluids are usually used in Daniudi gas field, but it had little positive effect on the formation damage relieving, sometimes even aggravated formation damage. This article has developed a new bio-enzymatic completion fluid. The laboratory test results showed that the completion fluid can thoroughly clean out the mud cakes, evenly relieve the pore slugging damage, and greatly reduce the formation water-sensitivity and water-blocking damages. It is also environment- acceptable without any toxic materials. The completion fluid has been applied in 15 horizontal wells in Ordos Daniudi gas field. The results of applications showed that the skin factors of all wells obviously decrease, especially in Well DX-1, the skin factor decreases to -2.3, and the Shan-1 formation has firstly got a good production without any stimulation treatments. The productions of all the wells are more than double times than those of former adjacent wells.
Air Injection in Heavy Oil Reservoirs - A Process Whose Time Has Come (Again)
Authors: Ursenbach M.G. , Moore R.G. , Mehta S.A.
Published: June 2014

Abstract

Air injection in heavy oil and bitumen reservoirs, also known as in-situ combustion or fireflooding, is an enhanced recovery process that has been around for several decades. While on paper or in the laboratory this oil recovery process shows tremendous potential, its success in past field applications has been spotty at best.

Times have changed, and so has our understanding of air injection-based oil recovery processes. Our available technologies for accessing and producing the reservoir and our emphasis on reducing environmental impacts have changed as well. In short, the industry is smarter, has better technology, and maintains a significant commitment to sustainable resource development.

This paper reviews portions of the past history of air injection in Canadian heavy oil and bitumen reservoirs; discusses the significant advances in our understanding of the in-situ process; reviews currently successful air-injection projects; summarizes the keys to successful implementation of air-injection-based recovery processes; and proposes several novel applications of air injection, including hybrid processes with steam or vapour solvent, in-situ upgrading, in-situ steam generation, and in-situ gasification.

Introduction

Since its accidental discovery in the early 1900s, the use of air injection as an enhanced oil recovery process has experienced a somewhat checkered history. In the 1950s and 1960s, it was actively and successfully advanced as a thermal process for heavy oils in California. Many of those projects have been summarized by Chu(1) and Sarathi(2). The successes in California brought in-situ combustion or fireflooding to Canadian heavy oils and bitumens in the 1960s to 1980s. While there were some successes in these pilots and projects, there were many more failures, and air injection in heavy oils never seemed to reach its theoretical potential.

In the two decades that have elapsed since then, significant research efforts have been made to understand both the causes of failures and successes in past in-situ combustion projects. At the same time, the heavy oil industry has evolved significantly.
Valuation of Swing Contracts by Least-Squares Monte Carlo Simulation
Authors: Willigers Bart J.A. , Begg Steve H. , Bratvold Reidar
Published: June 2014

Natural gas and electricity are commonly traded through swing contracts that enable the buyer to exploit changes in market price or market demand by varying the quantity they receive from the producer (seller). The producer is assured of selling a minimum quantity at a fixed price, but must be able to meet the variable demand from the buyer. The flexibility of such contracts enables both parties to mitigate the risks and exploit the opportunities that arise from uncertainty in production, demand, price, and so on. But how valuable are they? Traditional net present value (NPV), based on expected values, cannot value this flexibility, and the traditional options/valuation techniques could not model the complexity of the terms of such contracts.

Taking gas contracts as an example, this paper seeks to (a) raise awareness of how flexibility creates value for both parties and (b) show how least-squares Monte Carlo (LSM) simulation can be used to quantify its value in dollar terms, from the perspective of both producer and buyer. Because the value of flexibility arises from the ability it gives to respond to fluctuations (e.g., in commodity prices), a useful model of swing contracts needs to reflect the nature of these fluctuations.
CO2-Storage Capacity—Combining Geology, Engineering and Economics
Authors: Allinson W.G.. G. , Cinar Y.. , Neal P.R.. R. , Kaldi J.. , Paterson L..
Published: June 2014

This paper argues that any carbon dioxide (CO2) capacity-estimation method requires a combination of geological, engineering, and economic analyses to provide rigorous capacity estimates. It also argues that the classification of capacity estimates should follow concepts in the existing SPE Petroleum Resource Management System (PRMS) (SPE 2007) as closely as possible. The paper takes the discussion of CO2-storage capacity significantly further. It also aligns storage-capacity definitions more closely to the widely accepted PRMS.

Numerous authors and organizations have proposed CO2-capacity classification and calculation systems. In most of them, there is a definition of CO2-storage capacity that is intended to parallel the definition of petroleum reserves—namely, the volume of hydrocarbons that can be commercially recovered from known accumulations from a given date. However, each of the proposed systems applies economics only at the highest classifications of their systems. This is attributed to the infancy of the carbon-capture-and-storage (CCS) industry and/or the lack of a carbon price. However, in this paper, we demonstrate how economics combined with analytical and numerical injectivity modeling on the basis of geological models of the subsurface can help determine practical storage capacity.

In doing this, the paper makes observations about methods for estimating storage capacity, shows results of reservoir simulations and economic analyses, draws on SPE and internationally accepted methodologies and definitions of petroleum resources, and discusses how equivalent definitions can be applied to storage capacity. Finally, the paper provides recommendations for an improved CO2-storage-capacity classification system.
Introduction of A New Well Design to The Narrabri Coal Seam Gas Project
Authors: Hedger Linda K. , Cunnington Mike
Published: June 2014

Reservoir studies indicated that horizontal wells drilled in seam and intersecting vertical production wells were the optimal design to produce coal seam gas from the Narrabri CSG Project. An aggressive campaign of production pilots was drilled in 2009 and early 2010 to prove the potential of three coal seams in the Project area. The pilot wells included two dual lateral horizontal wells, with each horizontal well intersecting three vertical wells; a tri-lateral horizontal well which intersected four vertical wells; two long and three short single lateral horizontal wells intersecting one vertical well each; and three short, single lateral horizontal wells drilled from a single drilling pad to intersect three vertical wells. The importance to the company of the results required a high degree of certainty in well construction success.

There was very little time for rig start up issues to be addressed before the first horizontal well was drilled and early development of a competent wellsite team was essential. With little precedent and many unknowns, a low risk, fully engineered approach to the well design and drilling operations was adopted.

Connection of the vertical and horizontal wellbores is critical, and intersection techniques have been developed and refined. The Rotating Magnet Ranging System was introduced to Australia for this project, and adoption of this technology has subtle implications for directional drilling equipment and techniques. The wellbore hydraulics design and management while drilling program differed in several respects to conventional horizontal drilling, and performed very well.

The selection of the rig package, down-hole equipment and personnel underpinned the success of the 2009 – 2010 drilling campaign, and is described. The technical standards developed by the operation will interest other coal seam gas operators who face the challenge of economic extraction of coal seam gas, particularly from anisotropically fractured or deeper, lower permeability coals.