bluuebunny/crossref_metadata_2025 huggingface dataset:
Practical Control of SAGD Wells With Dual-Tubing Strings
Authors: Stone Terry W. , Brown George , Guyaguler Baris , Bailey William J. , Law David H.S.
Published: June 2014

Practical methods of operating dual-/triple-tubing strings, on the basis of temperature monitoring that is currently available, to achieve uniform steam-chamber development and enhanced production in a steam-assisted-gravity-drainage (SAGD) process, are presented. The work is motivated by the fact that numerous operators use dual-tubing strings for designing and optimizing steam-chamber development. Flow in the region of the SAGD horizontal well pair is often irregular, and dual-tubing strings may help to even out and improve both injection and production. Problems that operators have with multiple tubing strings in wells include their control and design. In this work, the injector and the producer will have two tubing strings each: one landed at the toe and the other at the heel. Control points are applied on each injection tubular. Injection at these control points is regulated by a proportional- integral-derivative (PID) feedback controller monitoring temperature differences between injected and produced fluids. A brief examination and discussion of the performance of control points in the production tubulars are also included. The PID controller will attempt to accomplish two goals: (i) to achieve evenness in injection and production conformance along both wells and (ii) to enforce a specified temperature offset between the injector and producer in order to improve oil production and reduce steam production and injection. Sensitivity of the feedback controller will be examined for (a) heterogeneity where several synthetic permeability patterns will be tested to gauge the effectiveness of coping with reservoir complexity, (b) update frequency where a comparison will be made between instantaneous and periodic updating of the controller error terms, and (c) ability of the controller to cope with early temperature rises in produced fluids. Well monitoring is accomplished through the use of high-temperature fibre-optic temperature sensing that is currently available. Results and further discussion are offered on whether an additional tubular landed at the midpoint of both wells will benefit production from a heterogeneous reservoir.
Design of Caprock Integrity in Thermal Stimulation of Shallow Oil-Sands Reservoirs
Authors: Yuan Yanguang , Xu Bin , Palmgren Claes
Published: June 2014

Stakeholders in in-situ oil-sands development take caprock-integrity issues seriously. The industry is faced with the challenge of determining an optimal operating pressure in the reservoir where, in general, the pressure should stay significantly low to ensure the caprock integrity while being significantly high for enhanced oil production and economics. This paper presents a comprehensive work program on the subject for a shallow oil-sands play. Caprock integrity considers the induced stress and deformation in a caprock during the thermal stimulation of an oil-sands reservoir. A minifrac-test program is undertaken to define the original in-situ stress state. Laboratory tests are carried out to measure the deformation and strength properties. Simulations are run to calculate the induced stresses and evaluate them against the mechanical strength. This paper describes some important quality-control issues for these activities. For the minifrac tests, multiple cycles and use of flowback are promoted for enhanced efficiency and accuracy. Laboratory tests are recommended on whole cores in a drained condition at a slow strain rate. Numerical simulations should use site-specific and laboratory-measured material properties. On the basis of the limited sensitivity analyses, the thermal expansion coefficient of the reservoir and Young's modulus of the caprock are found to significantly affect the caprock deformation and/or induced stresses.
Viscosity Prediction for Solvent-Diluted Live Bitumen and Heavy Oil at Temperatures Up to 175-deg-C
Authors: Motahhari Hamad , Schoeggl Florian , Satyro Marco , Yarranton Harvey
Published: June 2014

Accurate predictions of heavy-oil and bitumen viscosity as a function oftemperature, pressure, and composition are required for the design of thermaland solvent-based recovery methods. In this case study, the applicability ofthe recently developed Expanded Fluid (EF) viscosity model is tested onmeasured viscosities of diluted dead and live heavy oil and bitumen attemperatures from 20 to 175°C and pressures up to 10 MPa. Density and viscositydata were collected for a condensate solvent, dead (gas-free) bitumen, and deadheavy oil from western Canada, and for the corresponding live oils and dilutedmixtures of the dead and live oils with condensate solvent. Solubility,density, and viscosity data for heavy oil saturated with carbon dioxide(CO2) were obtained from the literature. The model was fitted to thedata of the dead oils and the condensate with average relative deviations lessthan 11%. The viscosity of the live bitumen and heavy oil was then predicted towithin 21 and 31% of the measured value on the basis of measured and calculatedlive-oil densities, respectively. Diluting the live and dead bitumen with 3 to30 wt% condensate or carbon dioxide reduced the viscosity by one to threeorders of magnitude, and the viscosities were predicted with an averagerelative deviation less than 16 and 24% on the basis of measured and calculatedmixture densities, respectively.
Saudi Aramco Intelligent Field Data Exchange Experience Using PRODML: Case Study
Authors: Beshri Abbas , Nixon David , Nasser Nasser , Suhaibani Raed , Muhawes Hamad
Published: June 2014

The rapid evolution of technological advancements in Intelligent Field equipment, real time monitoring & optimization over the past few years has contributed significantly to increasing production potential, recovery factor, and efficiency with the safest and environmentally sound practices. To achieve optimum results of the Intelligent Fields program, a reliable information infrastructure and architecture must exist.

Successful Intelligent Field implementation is based on two major components. The first one is a robust data acquisition and delivery infrastructure which is the backbone component of Saudi Aramco's Intelligent Field Surveillance Layer. Saudi Aramco has developed and implemented a set of standards, specifications, and guidelines to address and meet intelligent field requirements in terms of data types, frequency, resolution, security, integrity, quality, and reliability.

The other major and equally important component is the data processing and exchange workflows. This component plays an important role in achieving the other Saudi Aramco's Intelligent Field layers which are Integration, Optimization, and Innovation. Standardization of hydrocarbon production's data exchange between heterogeneous applications will considerably help to accomplish the overall objectives of the Intelligent Field Project.

Saudi Aramco's strategic aim is to implement a comprehensive E&P standards-based information architecture. The previous successful adoption of WITSML (Wellsite Information Transfer Standard Markup Language) enabled Saudi Aramco to standardize the drilling and completion information architecture. It allowed Saudi Aramco to leverage their investment in instrumention to enable new capabilities for automation and optimization that would otherwise be impossible or difficult to achieve. Also, it reduces the cost of information exchange between software and replacing or substituting software to benefit from improved functionality.

This paper will highlight Saudi Aramco's experience and methodology of assessing PRODML (Production Markup Language) functionality and usability in a pilot project. It will highlight examples, challenges, benefits, and limitations of the production standard PRODML.
Is Formation Damage an Issue in Shale Gas Development?
Authors: Wang Q. , Guo B. , Gao D.
Published: June 2014

Large scale hydraulic fracturing operations are often required for enhancing productivity of wells in shale gas formations. Due to the shally characteristics of the formation rock, the productivity of the hydraulically fractured gas wells seems to be very vulnerable to the damage by the fracturing fluids. The damaging mechanisms are believed to include fluid invasion, proppant embedment, gel filter cake at the fracture face, and the gel residue in the proppant pack. The relative significance of the formation damage due to each of the mechanisms is not clear. This paper presents result of investigations based on a new analytical model.

A new analytical well productivity model was developed in this study, considering the matrix cross-flow to long fractures and non-linear influx to short fractures. A new model involves parameters that describe the effects of fracture fluid filtration, proppant embedment, gel filter cake at the fracture face, and the gel residue in the proppant pack on the productivity of fractured gas wells in shale gas formations. Sensitivity analyses with the model show that, fracturing fluid invasion, proppant-embedment layer, gel filter cake residue at the fracture face, and gel residue inside the fracture may reduce well productivity by upto 12.5%, 0.6%, 6%, and 7%, respectively. The significance of the damage to well productivity should not affect gas production rate in a way that would be noticed.
Chevron's Digital Oilfields Solutions and Base Business Processes Maximize Value at McElroy Field, West Texas
Authors: Taylor William C
Published: June 2014

Chevron's digital energy program, i-field, began in 2002. Its focus is to enable integration of asset activities, relevant-time data, analysis and decision-making, and the design of purpose-built workflows to implement new i-field solutions.

The McElroy Field is a large waterflood located in the Permian Basin. Waterflood management at the McElroy is challenging due to reservoir complexity combined with drilling activity, well work, well count, varying artificial lift systems, high fluid volumes, and multiple injection systems. To efficiently manage the field, the technical team embraced i-field solutions and Chevron Base Business processes. The result is an efficient operation which is managed by exception using real time data.

The McElroy Team worked with Chevron's i-field team to map waterflood management workflows. The workflow designs reflected decisions being made, data requirements, data sources, and data quality. Subsequently, tools were developed that could access the data, apply filters, and present the results for review. To enhance the usage of the integration tools, an Asset Decision Environment (ADE) was built, enabling faster and more informed decision-making. The McElroy team also implemented Chevron's Integrated Production System Optimization process. A tool was built to capture facility information and the theoretical capacity. Forecasted production volumes were checked against equipment capacity to identify bottlenecks.

Application of i-field tools and the IPSO process have significantly impacted McElroy. The number of injectors within 10% of their target rate increased from 185 to 275 wells within 8 weeks of IMET implementation. The number of prospective workovers increased to over 100 wells once a well surveillance tool was incorporated into daily workflows. There has been a flattening of production decline directly related to improved injection and production well management made possible through the use of digital i-field tools and solutions.
A Two-Level Strategy to Realize Life-Cycle Production Optimization in an Operational Setting
Authors: van Essen G. M. , Van den Hof P. M. , Jansen J. D.
Published: June 2014

We present a two-level strategy to improve robustness against uncertainty and model errors in life-cycle flooding optimization. At the upper level, a physics-based large-scale reservoir model is used to determine optimal life-cycle injection and production profiles. At the lower level these profiles are considered as set points (reference values) for a tracking control algorithm, also known as a model predictive controller (MPC), to optimize the production variables over a short moving horizon based on a simple data-driven model. We used a conventional reservoir simulator with gradient-based optimization functionality to perform the life-cycle optimization. Next, we applied this optimal strategy to a set of reservoir models with markedly different geological characteristics. We compared the performance (oil recovery) of these models when applying the life-cycle strategy with and without the corrections provided by the data-driven algorithm and the tracking controller. In this theoretical study we observed that the use of the lower-level controller enabled successful tracking of the reference values provided by the upper-level optimizer. In our example, a performance drop of 6.4 % in net present value, caused by differences between the reservoir model used for life-cycle optimization and the (synthetic) true reservoir, was successfully reduced to only 0.5% when applying the two-level strategy. Several studies have demonstrated that model-based life-cycle production optimization has a large scope to improve long-term economic performance of water flooding projects. However, because of uncertainties in geology, economics and operational decisions, such life-cycle strategies cannot simply be applied in reality. Our two-level approach offers a solution to realize the theoretical potential of life-cycle optimization in a more operational setting.
Automation in Wellbore Stability Workflows
Authors: Wessling Stefan , Bartetzko Anne , Pei Jianyong , Dahl Thomas
Published: June 2014

Wellbore instability accounts for a significant amount of nonproductive time. Continuous improvement of today's technologies enables real-time analysis of acquired data to identify and remediate potential drilling hazards. Efforts toward the automation of relevant steps and processes for real-time wellbore stability modeling, monitoring, and calibration are considered highly important. Automation adds expertise to the rigsite engineers and enables simultaneous supervision of more than one well for remote operating engineers.

The complexity of the data flow, the reliability of the models, and the personnel required for monitoring pose great challenges for automation. Take pore pressure analysis as an example; some methods often require manual input from the user for placing normal compaction trend lines. Data used for pore pressure calibration (e.g., gas data) are more qualitative indicators rather than precise quantities. Important data are obtained only at discrete locations, such as leak-off tests for fracture gradient estimation. These examples illustrate the diversity of relevant data and information, which have to be properly managed.

In this paper we present some examples of the automation of single modules of a geomechanical analysis workflow. These include automatic setting of a normal compaction trend line and determination of the onset of overpressure using statistical methods, image interpretation algorithms to identify depth and width of breakouts, and automatic shale discrimination at the bit with drilling vibrations. These modules eventually become the building blocks of a complete automation system for wellbore stability.
Nikaitchuq ERD: Designing for Success on the North Slope of Alaska
Authors: Abahusayn Mishal , Foster Brandon , Brink Jason , Kuck Marc , Longo Joseph
Published: June 2014

A 52 well heavy oil field development targeting shallow (3,400-4,000 ft TVD) sands on the north slope of Alaska was initiated in 2008. Horizontal wells of 11,000 to 13,000 ft MD were drilled early in the program. These initial wells served as "data-gathering and technology-proving" opportunities leading up to the eventual 23,000 ft MD wells. Key technical challenges include equivalent circulating density (ECD) and drag management.

ECD management became essential in the 8½" production hole section of the longer wells. A relatively narrow (<600 psi) mud weight window necessitated changes to casing, drill-string, drilling fluids, and operational parameters. Lighter weight production casing allowed drilling a larger production hole (8¾" vs. 8½"). A tapered drill-string, reduced mud rheology, and reduced flow rate all became a necessary part of the ECD management solution.

Advanced drag management techniques are required to install the 9⅝" production casing, 5½" production liner, and 4½"x3½" intelligent inner-string completion. The 9⅝" casing is installed using the "buoyancy assist" method (ie, "floatation") so it may be "pushed" and reamed in the hole beyond the point of negative weight. The lower completion consists of a 5½" slotted liner with swell packers. Centralizers on the liner were changed from non-rotating to fixed, which allowed breaking axial drag while reaming the liners to depth.

Extensive torque and drag modeling was used to plan intelligent inner-string completions on the injector wells, which included injection control devices, swell packers, and a fiberoptic distributed temperature sensor (DTS) to monitor injectivity.

The full length paper will discuss the technical challenges, well design solutions, and operational practices that were trialed and implemented to enable extended reach wells to be successfully drilled on the edge of the industry experience envelope with all wells meeting targeted objectives.
Artificial Neural Network Drilling Parameter Optimization System Improves ROP by Predicting/Managing Bit Wear
Authors: Gidh Yashodhan , Purwanto Arifin , Bits Smith
Published: June 2014

Tool manufacturers have made significant progress improving downhole drilling technologies, but little effort has focused on optimizing the drilling process. The set-it-and-forget-it approach and inherent inefficiencies of the automatic driller are inadequate for keeping bit parameters matched to lithology and wellbore conditions. The industry requires a new methodology to help rig-site personnel make informed drilling parameter decisions based on real-time offset data analysis that increases operating efficiency to reduce drilling costs.

To solve the problem an artificial neural network (ANN) drilling parameter optimization system was developed to provide rig-site personnel real-time information to ensure maximum run length from all bits and downhole tools at the highest possible ROP. Benefits of the new system include extended tool life, fewer trips and the ability to manage the bits dull condition.

The objective is to replace the human factor of applying operating parameters such as WOB and RPM with the intelligent ANN learned experience. Using the ANN software system, operating parameters can be selected based on the documented physical rock characteristics (offset log data) of formations being penetrated and then fine tuned for the bits specific cutting structure and wear rate. By following the real-time ANN recommendations, changes can be implemented to increase overall ROP while maximizing bit life by managing the dull condition.

The overall project results were positive and proved successful in all the trails carried out after this field trial. This paper will address the methodology of the new approach and highlight the importance of planning and implementing the drilling parameters in realtime.
Hydraulic Fracture Production Optimization With a Pseudo-3D Model in Multi-layered Lithology
Authors: Yang Mei
Published: June 2014

Systematic design and optimization procedures for hydraulic fracturing are available using two-dimensional (2D) (with constant fracture height) and pseudo three dimensional (p-3D) models to maximize well production by optimizing fracture geometry, including fracture height, half-length and width.

A multi-layered p-3D approach to design is proposed integrating Unified Fracture Design (UFD), fracture propagation models and Linear Elastic Fracture Mechanics (LEFM) relationship to generate optimized fracture geometry, including fracture height, width and half-length to achieve the maximized production. Containment layers are discretized to allow for plausible fracture heights when seeking convergence of fracture height and net pressure.

UFD sizes the fracture geometry to physically optimize the hydraulically fractured well performance. The Proppant Number is a correlating parameter, which in turn provides the maximum dimensionless productivity index (JD) corresponding to the optimum dimensionless fracture conductivity, CjD. Once the latter is determined, the fracture dimensions, i.e., fracture length and width, are set. However, UFD in its original form needs fracture height as an input parameter.

PKN or KGD fracture propagation models predict hydraulic fracture geometry and the associated net pressure. Linear Elastic Fracture Mechanics (LEFM) relationship calculates fracture height by finding the net pressure distribution at layers, which plays an important role when the fracture is propagating in the reservoir. In multi-layered reservoirs, the net pressure of each layer varies as a result of different rock properties. This study considers the contributions of all layers to the stress intensity factor at the fracture tips to find the final equilibrium height defined by the condition where the fracture toughness equals the calculated stress intensity factor based on LEFM. After an equilibrium height and the corresponding net pressure at the center of perforation are obtained, PKN/KGD models are used again, to calculate fracture width and half-length at each layer. This work also allows for a calculation of the fracture height that would not propagate into unintended layers (i.e. gas cap and/or aquifer)
Expanding the Hydraulic Fracturing Options on Reservoirs with Water Zones in Western Siberia
Authors: Mendez Alfredo , Mazhirin Yury , Astafyev Vladimir , Alekseev Boris , Bortey Pavel
Published: June 2014

Hydraulic Fracturing in Western Siberia, Russia is a common practice that the need of stimulating wells in mature oil fields cannot be limited to non-complicated reservoirs. Wells requiring hydraulic fracturing with water zones either above or below is what we mean as reservoirs that require techniques that are out of the ordinary and day to day operations. A technique using dry solid material to contain the hydraulic fracture job within the zone of interest has been used in several wells and will be presented in this paper. The oil field Nivagalskoe which is located in Nizhnevartovsk area, Western Siberia, Russia is considered a mature oil field where due to the low value of the reservoir permeability, hydraulic fracturing these reservoirs require more than a skin bypass frac. Achieving a lengthier propped frac and descent net pressure increase is always a challenge on any hydraulic fracturing job execution but is always a must for the oil fields in the Nizhnevartovsk area. The challenge becomes when there are water zones close to the zone of interest to be stimulated via hydraulic fracturing. The objective is only not to design a job that will be limited in height by optimizing parameters commonly used in limiting frac geometry but to guarantee at best that the frac will not grow into the water zone. Several cas histories will be presented where all cases the water cut was measured before and after the hydraulic fracturing job. The technique used and recommendations will be presented to optimize future jobs. All other options to limit frac geometry considered will also be presented.
Cost-Effective Acid Stimulation of Carbonates Using Seawater-Based Systems Without Calcium Sulfate Precipitation
Authors: Berry S. L. , Boles J. L. , Smith K. L.
Published: June 2014

Water is a key element in oil and gas operations. Many operations need and/or are performed most ideally with fresh water, but its availability is decreasing in some locations around the world. One area of particular concern is offshore operations to stimulate carbonate formations.

Acid stimulation fluids are usually mixed with fresh water, but if fresh water supplies are limited or unavailable, seawater is sometimes substituted in part or full. However, when acid systems are mixed with seawater containing high levels of sulfate ions, calcium sulfate precipitates as the acid reacts with limestone or dolomite formation. The extent of calcium sulfate deposition or scaling, although sometimes accepted or ignored by some customers, can result in post-stimulation results far below their true potential.

Various technologies can remove sulfate from seawater; however, these technologies are expensive and logistically challenging or impractical to use on offshore installations or conventional stimulation vessels. Instead, a newly developed acidizing fluid system provides a cost-effective method to chemically inhibit calcium sulfate precipitation from sulfate-laden seawater during acid reaction, resulting in more effective stimulation of carbonate rock. This fluid system eliminates the need to pre-treat seawater, greatly simplifying logistics while maximizing stimulation efficiency.

This paper will demonstrate that calcium sulfate does precipitate from conventional acidizing fluid systems mixed with seawaters containing high levels of sulfate. It will further show that this precipitation decreases the solubility/stimulation of carbonate rock. Finally, this project will introduce and show the efficiency of a chemical method to treat seawater-mixed acid systems to effectively minimize or prevent the precipitation of calcium sulfate solids during carbonate acid stimulation treatments.
Sustaining a Dynamic Revolution: How BP Is Growing the Value Delivered From Transient Flow Modelling and Control
Authors: Calvert Patrick , Griffiths Peter
Published: June 2014

Steady state flow modelling has become common practice across the industry. Over the past decade, continued developments in the underlying modelling software have led to a greater up-take in steady state modelling as clear solutions emerge for a wide range of operational problems.

Whilst steady-state modelling has reached a level of maturity, dynamic modelling is less established as an operational support tool. This contrasts with an ever growing list of dynamic operability issues that have emerged from operating more challenging fields. Although firmly established in the flow assurance community, transient flow modelling has yet to achieve the same critical mass with the petroleum engineering community. The additional technical complexity of dynamic modelling means that it is more likely to be used in bespoke design studies than in the support of daily operations.

Within this paper, the challenges of developing a sustainable dynamic modelling capability will be discussed in reference to three phases: demonstrating value; crystallising interest and building regional capability. For each phase, supporting evidence will be given from a variety of projects including slug control, well start-up and well deliquification.

Dynamic modelling is beginning to play a significant role in BP's operations. The significance of dynamic modelling and control in delivering safe, stable and optimal performance is now well understood across the company. The remaining challenge is to crystallise recent success into a fully sustainable dynamic modelling capability.
New HT/HP Technology for Geothermal Application Significantly Increases On-Bottom Drilling Hours
Authors: Orazzini Simone , Kasirin Regillio , Ferrari Giampaolo , Bertini Alessandro , Bizzocchi Isabella , Ford Robert , Li Qingxiu , Zhang Ming
Published: June 2014

Geothermal energy has been use for centuries to satisfy general heating requirements. The modern geothermal plant is powered by production wells drilled to a source rock to produce steam at the surface. Depending on the location and depth, source formation temperatures vary.

In Italy, the operator must penetrate very hard and abrasive sediment and metamorphic formations to access steam in the granite basement formation. Historically, this was accomplished with a tungsten carbide insert (TCI) roller cone bit (RC). Standard geothermal bits and components, including grease and elastomer seals, are adequate for temperatures up to 150°C (302°F). Beyond these temperatures, the bit’s internal components and lubricating material can degrade causing bearing failure limiting on-bottom drilling hours. In the application, the bottom hole temperature is approximately 180°C (350°F) and in some instances it can exceed 280°C (536°F). The extreme heat reduces on-bottom drilling hours leading to multiple bit runs/trips that drive up development costs. The operator required new roller cone technology that would endure the downhole environment.

To solve this challenge, a series of tests were conducted with temperature resistant elastomers and grease compounds in a controlled laboratory environment. The experiments resulted in a new line of roller cone bits equipped with an innovative bearing system that includes new proprietary composite elastomer seals with Kevlar® fabric and a proprietary high temperature grease formula. These innovations increased seal life, lubricity and load capacity at elevated temperatures for HT/HP applications.

The new geothermal bit technology has been run in the Italian application with outstanding results. Compared to standard roller cone products, the high-temperature bits have greatly increased on-bottom drilling hours while reducing total bit consumption and costly tripping for bit change out. Since successful development of the geothermal project is tied to reducing drilling costs, the new bit technology has significantly improved project economics. The authors will discuss development of the high temperature seal and grease compounds for drilling the granite basement source rock. They will also outline changes to the TCI cutting structure, field application, dull grades and bit performance data.
The Future of Surveillance—A Survey of Proven Business Practices for Use in Oil and Gas
Authors: Lochmann Mark
Published: June 2014

Surveillance in one form or another has been used in oil and gas production almost since the industry began. The initial goal was relatively simple and straightforward: monitoring output against production targets for individual wells and troubleshooting those same wells when problems occurred. The actual scope of what could be accomplished was limited by available resources and lack of tools and technology, so only a very few high-value wells could be monitored closely.

With modern complex oil- and gas-production operations, the goal of surveillance has evolved from ensuring a single well's performance to managing a producing asset against its potential—a much loftier endeavor that must consider each of the system components, the interaction of those components, and the impact of factors external to the system. Traditional approaches to surveillance are no longer adequate to meet the current and continuously emerging and increasingly complex requirements of oil and gas operations. Modern and next-generation surveillance systems must deliver more.

More recently, in both mature fields and greenfields, the industry has seen increased implementation of more-sophisticated solutions with richer capabilities (e.g., monitoring centers that feed data into real-time displays; the enabling of operations staff to see the status of all key measurements; and model-based, integrated workflows to automate and facilitate operational excellence). The addition of advanced analytics, expert systems, and process automation (all of which routinely leverage real-time information) has taken surveillance from gathering production data on grease books to sophisticated solutions that combine business or operational intelligence with automated technical calculations. Indeed, these are the types of surveillance solutions expected by forwardthinking managers. However, despite these successes, widespread uptake of these types of solutions is slow, as is often the case in our industry.

This paper provides a survey of business practices proven in other complex industries, including management by exception (MBE), business intelligence (BI), situational awareness (SA), model-based decision support (MBDS), advanced process control (APC), and consequential analysis (CA). With learning from use in other industries, these business practices, enabled by state-of-the art information technology, can be combined and implemented to build next-generation surveillance solutions that will allow oil and gas producers to manage production assets against their potential in a safe, environmentally responsible way and in support of corporate goals.
Closed-loop Feedback Control for Production Optimization of Intelligent Wells under Uncertainty
Authors: Dilib F. A. , Jackson M. D.
Published: June 2014

Significant challenges remain in the development of optimized control techniques for intelligent wells, particularly with respect to properly incorporating the impact of reservoir uncertainty. Most optimization methods are model-based and are effective only if the model or ensemble of models used in the optimization capture all possible reservoir behaviors at the individual well and completion level. This is rarely the case. Moreover, reservoir models are rarely predictive at the spatial and temporal scales required to identify control actions. We suggest that closed-loop feedback control strategies, triggered by monitoring at the surface or downhole, can increase NPV and mitigate reservoir uncertainty. We do not neglect reservoir model predictions entirely; rather, we use a model-based approach to optimize adjustable parameters in the feedback control strategies. We assess the implementation of an intelligent horizontal well in a thin oil reservoir in the presence of reservoir uncertainty, and evaluate the benefit of using different inflow control actuators in conjunction with surface and/or downhole monitoring equipment.

Four inflow control strategies are tested. The first is an open-loop approach, using a fixed control device to balance inflow along the well, sized prior to installation. The second and third are closed-loop feedback control strategies, employing intelligent completions that can be controlled from the surface. The second strategy uses on/off inflow control devices, operated according to surface flow rates and phase measurements obtained during zonal well tests. The third strategy uses variable control devices, operated according to downhole multiphase flow meters. The fourth strategy employs a gradient-based optimization algorithm to find the dynamic optimal inflow control behavior. This strategy assumes perfect reservoir knowledge and is implemented only for benchmarking of the feedback control strategies.

Our result suggests that closed-loop control based on direct feedback between reservoir monitoring and inflow valve settings can yield close-to-optimal gains in NPV compared to uncontrolled production, even if the reservoir does not behave as predicted. Open-loop control yields significantly lower gains in NPV and is also a riskier strategy, because unpredicted reservoir behavior can lead to negative returns. Closed-loop feedback control can mitigate uncertain reservoir behavior, even when this lies outside the range of model predictions; moreover, the uncertainties which have the most significant impact on production may not be the most difficult to mitigate.
Simulation of Gel Filter Cake Formation, Gel Cleanup, and Post-Frac Well Performance in Hydraulically Fractured Gas Wells
Authors: Charoenwongsa S. , Kazemi H. , Fakcharoenphol P. , Miskimins J. L.
Published: June 2014

Polymer and gel damage is a major issue in the cleanup of hydraulically fractured gas wells. This paper addresses this issue by using a gas-water flow model which simulates fracture propagation with gel filter cake formation as mechanical trapping of polymer molecules on the fracture face and filtrate transport into the adjacent matrix. The model accounts for polymer as a chemical component. This approach is different than treating polymer as a highly viscous gel phase, which is the common method in most literature. In this model, the gel filter cake thickness is calculated based on experimental data. For leakoff, the model allows only the sheared polymer molecules, which are the major cause of formation permeability reduction, to cross the fracture face into the formation and adsorb on the matrix. Other features of the model include water blockage, non-Newtonian flow, non-Darcy flow, and proppant and reservoir compaction.
Statistical Analysis of Significant Factors Affecting Perforation Flow at Well Scale
Authors: Li Baoyan , Sun Datong , Satti Rajani
Published: June 2014

Well perforation rebuilds the communication between the wellbore of a cased well and the formation to produce gas/oil. Completion and reservoir engineers expect to maximize well production by the optimal design of well perforation. However, are perforation parameters the significant factors influencing the productivity of a perforated well? Will drilling and perforation damages, combined with perforation factors, significantly affect the production performance of the well? To address these technical concerns, we need to perform a sensitivity analysis to screen and rank the significant factors affecting the productivity of a perforated well.

The one-factor-a-time methodology has been used to perform a sensitivity analysis of the perforation flow. This methodology is simple, but the interactions between the factors are not considered and no ranking of significant factors is provided. To overcome these disadvantages we introduce the methodologies of experimental design and analysis to screen and rank the significant factors affecting the perforation flow at well scale.

In this study, a two-level factorial design is used to collect simulation results of perforation flow at well scale from the commercial computational fluid dynamics (CFD) software ANSYS FLUENT. Analysis of variance (ANOVA) method and regression analysis method are used to analyze and rank the significant factors affecting the perforation flow at well scale.From this sensitivity analysis study, we conclude:

The depth of penetration (DOP) is the most significant factor to the productivity and skin factor of the vertical well, if the shot density is six shots per foot and shot phasing is 60 degrees. The interactions between any two of the following factors: penetration depth, return permeability of the drilling-damage zone, and return permeability of the perforation crushed zone are significant to the skin factor of the vertical well. Permeability anisotropy is a significant factor to the productivity of a perforated vertical well. The radius of the perforation tunnel is not a significant factor influencing the skin factor of a well, and neither are the thicknesses of the drilling-damage zone and crushed zone of perforation.
Accelerating Regional Transformation Using a Centralised Business Process Repository
Authors: Newman Mark , Feineman David R
Published: June 2014

In a globally distributed oil and gas organization, transformation of business processes, adoption of digital oilfield technology and developing competencies of staff presents a significant challenge. Variations in culture, working practices, partial definitions of what constitutes ‘best practice’, and achieving sustainable change and creating an environment for continued change presents a complex picture for transformation delivery.

The Morphix Company and BP's Field of the Future Flagship have been working together for the past 7 years to adopt methods for business transformation based on a centralised repository of reference models. These are being used to support specific transformation projects in the areas of base management, well planning and construction, and other functions making use of digital oilfield technology.

The iterative development of centralised reference models, their management, and implementation will be discussed, specifically addressing how best practice is being captured, how reference models are evolved, how reference models are used in specific transformation projects, and how location specific implementations are handled in regional business units.

RESULTS/CONCLUSIONS
Methodology For Overcoming Bottlenecks Leading To Successful Implementation of Collaborative Working Environment
Authors: Al Azawi Bahir , Hafez Mohamed , Jakeman Simon , Al Bishr Ibrahim , Bin Amro Ahmed , Malvey Peter
Published: June 2014

While many papers talk about the benefits of Collaborative Work Environments (CWE), few have addressed the issues related to the design and implementation of the projects.

This paper covers the development of the NEB field CWE in Abu Dhabi Oil Company for Onshore Operations (ADCO), and addresses the experiences and learnings across all phases of the project. It addresses the development of the Smart Fields strategy and the planned coverage of CWEs across the producing field, the required IT infrastructure, the selection of applications and the development of workflows to support the CWEs and the significant project management and logistical challenges.

During the course of the project ADCO underwent a reorganization which aligned the company around its producing assets. The paper addresses the benefits that this change has made in implementing the CWE programme and highlights some of the change management issues faced by the team. Critical to the success of the project was to ensure staff quickly familiarized themselves with the new working environment and that a clear support structure was in place which could respond to technical problems and requests for assistance.

A key purpose of the paper is to share the acquired knowledge from implementing the project, covering both the successes and the challenges of overcoming bottlenecks, pitfalls and things that simply go wrong. In such, it provides the leadership practitioner with a balanced methodology of process and necessary soft skills to map out a road which manages the risks and avoids the potholes.
Optical Fibers: The Neurons For Future Intelligent Wells
Authors: Koelman Johannes M. , Lopez Jorge L. , Potters Johannes H.
Published: June 2014

Fiber-optic distributed sensing is known in the oil and gas industry as an enabler for permanent temperature profiling along entire well paths. This application is limited to recovery processes with a pronounced thermal signature. Currently, we witness a confluence of novel fiber-optic technologies promising a much wider and more complete range of subsurface measurements. This opens new avenues in well and reservoir surveillance and highlights the opportunity for fiber-optic sensing to become a pervasive oilfield technology.

In this paper we discuss field trials that combine Distributed Temperature Sensing (DTS), Distributed Strain Sensing (DSS) and Distributed Acoustic Sensing (DAS). These trials demonstrate the potential of fiber-optic sensing technology for well integrity monitoring, gas lift optimization, in-flow profiling and downhole seismic acquisition.

Essential to realizing this potential is the development of cost-effective, easy-to-deploy fiber-optic cables optimized for these combinations of fiber-optic measurements. We also highlight the business integration challenge of handling, storing, and interpreting data volumes that reach levels of 1 TB/well/day. We conclude that while significant technology challenges remain, with a broad range of oilfield technology providers working on derisking fiber-optic sensing technologies, the industry is on the verge of a step change in well and reservoir monitoring capability.
Efficient Use Of High-Frequency Data Through Production Data Management System Implementation
Authors: Creemer A. , Holy R. W. , Fuehrer F. , Mohajer M.
Published: June 2014

The McCully Field (New Brunswick, Canada) is highly instrumented and generates a massive quantity of high-frequency data stored in a data historian. Data time range and frequency of interest had to be manually retrieved through spreadsheet macros for analysis, plotting, and gas allocation. As the production history grew, the amount of data generated was overwhelming and unconsolidated, making the task of manual data handling and visualization both difficult and time consuming.

The implementation of a production data management system resulted in a fully automated, end-to-end workflow that acquires five-minute data from the Supervisory Control and Data Acquisition (SCADA) system into the operating database; performs accurate allocation of gas, condensate and water volumes; as well as creates and distributes daily production summaries to a custom email list in a matter of minutes.

The implementation of an automated approach was driven by five main objectives: automate production data acquisitionoptimize field production through real-time well surveillanceincrease data processing speed (reduce time spent on data handling, preparation, cleansing and reporting)take advantage of existing high-frequency databaseimprove communications regarding well performance between office and field operations

After a successful implementation, data acquisition time has been reduced from a manual 30 minutes to an automated 5 minutes each day. Daily production reports, instead of only being accessible through the server, are now automatically emailed to a distribution list within the company. Real-time well surveillance is now possible from the main office and not only through the SCADA system in the field, which provides the engineering group with a better understanding of individual well performance and also allows any production disruptions to be identified early and resolved efficiently. Finally, the consolidated database is now integrated with engineering analysis tools for further use of information, which ultimately increases the effectiveness of the technical team.
Using Semantic Technology to Auto-generate Reports: Case Study of Daily Drilling Reports
Authors: Giese Martin , Ornæs Jens I. , Overå Lars , Svensson Inge , Waaler Arild
Published: June 2014

The Daily Drilling Report (DDR), a compulsory report to the Norwegian Petroleum Directorate and the Petroleum Safety Authority (PSA) for operators on the Norwegian Continental Shelf, is an example of a task that typically requires integration of data from a variety of independent sources. Current documentation of DDR (EPIM, 2008) content specifies the reporting format in the form of an XML Schema document (XSD), using textual definitions for the explanation of terms.

We report on a case study that demonstrates the use of semantic technologies for the specification, and possibly also generation, of reports in the Oil and Gas sector based on a case study of Daily Drilling Reports. We discuss the underlying vision, present the case study in some detail and evaluate its results. We furthermore discuss the potential of the method for other kind of reports. Finally we conclude with a few recommendations.