bluuebunny/crossref_metadata_2025 huggingface dataset:
The Use of Connection and Total Gases Quantitatively in the Assessment of Shale Pore Pressure
Authors: Alberty Mark , Fink Kristi
Published: June 2014

Connection and total gas measurements were used qualitatively for decades in drilling oil and gas wells to identify overbalanced, underbalanced, or near-underbalanced pressure conditions (mud hydrostatic pressure relative to shale pore pressure). Results often conflicted with directly measured sand pore pressures (PP) and the pre-existing perceptions of shale PP. We propose a technique that allows mud gases to be used in a quantitative manner when (1) there is an increased understanding of the relationship between mud gases and shale PP, (2) the development of the logging-while-drilling (LWD) -based annular-pressure measurement allows for the real-time monitoring of downhole hydrostatic pressures, and (3) differences between sand and shale PP may exist as a result of the sand's structural position.

This paper presents time-based equivalent-circulating-density (ECD) behavior relative to block movement, flow rate, and total gas from Gulf of Mexico (GOM) wells, and explains the relationship to shale PP. These examples are quantitatively analyzed for shale PP. The results are compared with direct formation-pressure measurements within the sands.

Six principles guide pore-pressure interpreters on the quantitative use of mud gases. The principles define the pore-pressure values assigned to specific mud-gas observations as a function of recorded annular mud pressure. One can use the pore-pressure estimates in shale as calibration points for traditional shale-pressure indicators such as resistivity, velocity, or corrected drilling-exponent measurements.

This integrated technique yields an improved characterization of shale and sand PPs and can be used as input for well designs to increase reliability, safety, and drilling efficiency.
Estimating Proved Reserves in Tight/Shale Wells Using the Modified SEPD Method
Authors: Yu Shaoyong , Lee W. John , Miocevic Dominic J. , Li Dong , Harris Seth
Published: June 2014

Due to their simplicity, empirical production forecasting methods have been used by the petroleum industry for decades. Since 2008, a number of empirical methods have been introduced to the petroleum industry, specifically for wells located in tight/shale reservoirs. However, most of these new methods are not reliable for forecasting remaining reserves, although they may appear to be very good for forecasting EUR in wells in which a high percentage of the EUR has already been produced.

The Stretched Exponential Production Decline (SEPD) Method was introduced in 2010. Our results from analysis of both synthetic and actual field data by using SEPD have indicated that this method will most likely underestimate EUR in reservoirs with permeability ranging from 0.1mD to 0.0001mD. A modified SEPD (YM-SEPD) Method has therefore been developed to eliminate the SEPD Method's shortcoming by employing a new specialized plot to find all related parameters. This newly developed method is very easy to use and, most importantly, it will yield a much more reliable production and remaining reserve prediction for tight horizontal wells. With longer production histories, remaining reserves can be forecasted even more accurately and with a high confidence level.

Hundreds of horizontal wells including oil wells from various formations (Cadomin, Montney, Notikewin, Cardium, Barnett Shale, Muskwa, etc.), hydraulically fractured in various ways, have been analyzed using the modified SEPD (YM-SEPD) method. Results indicate that reliable EURs and production profiles can be predicted readily for wells having only two to three years of production history. For wells having less than two years of production history, the modified SEPD (YM-SEPD) Method can also yield reasonable production forecasts when coupled with Duong's empirical method.

This paper presents the application of the modified SEPD (YM-SEPD) Method to a number of actual and synthetic oil and gas wells to estimate their proved reserves, including horizontal wells producing dry, wet and retrograde gas as well as tight oil. These examples have had production histories with either observed or non-observed boundary-dominated flow (BDF). The examples also illustrate how the modified SEPD (YM-SEPD) method is capable of estimating proven reserves with high confidence.
Geomechanics Coupled Reservoir Flow Simulation for Diagnostic Fracture Injection Test Design and Interpretation in Shale Reservoirs
Authors: Padmakar A. S.
Published: June 2014

Diagnostic fracture injection testing (DFIT) is an extremely popular technique to generate direct estimates of some of the key characteristics of shale reservoirs. DFIT analysis is generally done using analytical models traditionally developed for high-permeability reservoirs. The use of DFIT to analyze tight shale reservoirs introduces additional issues regarding applicability of these techniques for tight systems as well as operational issues such as long well shut-in times to obtain reasonable reservoir parameters. In this work we conduct geomechanics coupled reservoir flow simulations in order to forward model and analyze DFITs for tight shale gas reservoirs. This capability greatly enhances our ability to efficiently design the DFITs for tight shale reservoirs. In this work we simulate a typical DFIT using a geomechanics coupled reservoir flow simulator and generate the pre-closure and after-closure pressure response from the flow simulation model. This response is then analyzed using a standard Nolte pre-closure and after-closure analysis technique with an objective to evaluate the reservoir properties. We not only we show the validity of the Nolte analysis technique for tight rocks but we also provide guidelines on the amount of shut-in time required to generate a reasonable estimate of the reservoir properties from DFIT pressure response. We also show that the geomechanics coupled flow simulation of DFIT can provide estimates on fracture dimensions which compare reasonably with those given by more traditional fracture design tools. We demonstrate that the geomechanics coupled reservoir flow simulation provides an additional advantage over traditional fracture design tools in that it can numerically model the system response even after fracture closure.
Reduction in Scale Build-up from Sub-surface Safety Valve Using Hydrophobic Material Coating
Authors: Kumar Deepak , Welch John C. , Xu Zhiyue
Published: June 2014

The spring cavities and the inner wall of the sub-surface safety valve can accumulate a thick and hard scale of BaSO4, CaSO4, CaCO3, and asphaltene in certain conditions during production. These scales can impede the smooth operation of the valve and pose potentially serious regulatory and safety risks, e.g. malfunctioning during well blow-out. Currently, exploration and production companies use flow tube exercise remediation tools to remove the scales. However, the approach is not preferable because it requires costly well intervention and is sometimes not feasible.

In the current study, hydrophobic coatings were fabricated to reduce the build-up of scale from downhole tools such as sub-surface safety valves, production tubing, and gas-lift mandrels. The coating is created from low surface energy materials and is combined with a specifically designed micro and micro-nano surface texture. A micro-scratch tester was used to determine the mechanical strength of the coating, and scale growth experiments were conducted in the laboratory to determine the efficacy of the coatings against scale build-up.
History Matching of a Successful Polymer Flood Pilot in the Pelican Lake Heavy Oil Field, Canada
Authors: Delaplace P. , Delamaide E. , Roggero F. , Renard G.
Published: June 2014

A successful polymer flood is being implemented in the Pelican Lake heavy oil field located in Northern Alberta (Canada). With primary recovery around 5-7 % and several billion barrels OOIP, the field offered a big target for EOR but polymer flooding had never been considered in such high viscosity oil (600 to 80,000cp) until the idea of using horizontal wells gave way to a very successful 5 horizontal wells polymer flood pilot in 2005, followed by a progressive extension to the rest of the field. This paper provides a brief description of the polymer flood pilot then focuses on the various steps involved to generate a realistic reservoir model to history match the pilot.

Polymer flooding in heavy oil reservoirs (1500 cp oil in the pilot area) using horizontal wells is really new and the response of the pilot was not totally expected. The oil rate has increased beyond expectations but more surprisingly, the water-cut has increased very slowly and is only in the 50-60 % range after 7 years of operations. History matching the pilot history was important in order to understand what was really taking place in the reservoir; it was performed using up to date Assisted History Matching techniques.

Good results have been obtained in terms of history matching. The model can therefore be used to investigate the influence on oil recovery of many parameters such as well length and spacing, injection rate, polymer concentration, slug size, and to evaluate additional recovery compared to continued primary recovery or waterflood.

History matching the pilot performance opens the door to a better understanding of polymer flooding in heavy oil reservoirs and to increasing the number of potential application cases.
Asphaltene Deposition in Capillary Flow
Authors: Seifried Christine Maria , Al Lawati Sadiqa , Crawshaw John P , Boek Edo S
Published: June 2014

Asphaltene precipitation and deposition may cause severe problems during production, transportation and processing of crude oil, hence affecting efficiency and cost of production in both upstream and downstream operations. During crude oil production they can deposit in rock reservoir pores, thus leading to possible blocking and formation damage. Despite significant research asphaltene deposition under flowing conditions remains barely understood. Here, capillary flow experiments were conducted to study asphaltene deposition by examining the pressure drop across the capillary as a function of different factors. Asphaltenes were precipitated with n-heptane from a crude oil/toluene mixture. Increasing the precipitant fraction led to greater precipitation which results in a faster deposition rate. A higher total volumetric flow rate also led to a higher deposition rate and a higher mass of deposited asphaltenes with more asphaltenes deposited at the entrance of the capillary. This was confirmed by images taken with a confocal laser-scanning microscope. Diffusive boundary layer theory was considered to explain the results which predict that the effective diffusive boundary layer thickness grows with the mean velocity ūs1/3, whereas our results showed a dependence on ū.
Hydraulic Fracture Design Flaws-Proppant Selection
Authors: Yang Mei , Economides Michael J. , Wei Chenji , Gao Chao
Published: June 2014

This work presents the statistical use of important elements of fracture technology in a number of major locations, primarily in Texas. The geographic analysis appears to be consistent and valuable: similar reservoirs in a basin call for similar treatments. The research will particularly focus on proppant selection, as one of the most important elements in both the physical success of a hydraulic fracture and its economic optimization. The paper also incorporates logistical costs such as proppant shipping to well site.

Completion data are summarized, specifically on fracturing treatments in the Eagle Ford, Marcellus and Barnett Shales and the Permian Basin. Production data from hydraulically fractured wells in the Permian Basin, Texas are included in the study. One of the observations from the production data is that cumulative production from natural proppants is superior to the production from treatments using synthetic proppant in the same fields. This is an interesting finding because with the higher conductivity of synthetic proppants, a higher production rate is often expected. The paper discusses the hydraulic fracture design flaw that causes the discrepancy.

Another conclusion is that in the reservoirs currently under exploitation, natural sand proppants are appropriate and the net present values of the treatments are superior to those of any synthetic proppant. This conclusion is not only because of the shallower depths (and therefore less crashing) but also because of the low-reservoir permeability, allowing for lower proppant-pack permeability.

With the theory guidance of the Unified Fracture Design approach and massive completion and production data analysis, this study can help the industry considerably to implement hydraulic fracture designs more effectively.
Improving EH&S Practices during Turnarounds in Facilities and Plants: A Process of Knowledge Capture and Transfer Worth Implementing
Authors: Daher Elie , Dowd Darrell
Published: June 2014

A well-executed maintenance shutdown or turnaround in processing facilities or plants can represent a source of competitive advantage for an organization. It can drive commercial performance, boost morale and bring recognition to high performing teams keeping everyone safe.

Maintenance shutdowns or turnarounds represent an increasingly significant challenge and an increasingly significant opportunity. Understanding the various EH&S issues facing previous turnarounds and most importantly how they were addressed is essential for the success of subsequent activities.

This paper discusses how to ensure the capture and dissemination of the wealth of knowledge generated and how to make proper use in order to impact the efficiency and effectiveness of these projects while keeping everyone safe.

There are three places or situations that a project can and should gather learnings; the planning phase, execution phase and completion phase. To ensure the maximum benefit from knowledge capture and transfer, two best practices have been developed - Needs Assessment and the Stewardship Report.

The Needs Assessment is a process used to review the work with key management stakeholders. While systems and processes are designed to maximize the efficiency in the delivery of safety resources for planned tasks during the turnaround, the Needs Assessment proactively identifies areas that are likely to generate unplanned work. This enables the creation of readiness plans that let you effect change quickly, before unplanned work becomes an issue or a source for delay and extra cost.

The Stewardship Report is a document that is used at the conclusion of a project to examine and evaluate how the contractors and company personnel performed during the project. It is an unbiased, objective recap of everything that worked and what didn't work as well. This long term comprehensive strategy for information flow and technology innovation driven by customer feedback ensures that lessons are learnt, mistakes avoided and successes repeated. Corrective actions and solutions are proposed, discussed and documented for implementation prior to the next project.

This paper studies these two tools, Needs Assessment and Stewardship Report in detail and provides practical examples and tips on how they can ensure knowledge capture and transfer in their organization.
Development and Field Testing of Advanced Ceramic Proppants
Authors: Mack Mark G. , Coker Chris E.
Published: June 2014

A unique family of advanced ceramic proppants has been developed based on formulated mixed-metal oxides. In contrast to conventional top-down ceramic proppant manufacturing, a bottom-up process is used to coat ceramic cores with highly-engineered layers of mixed-metal oxide. This process yields a very strong, light proppant with well-controlled porosity, and a narrow size distribution.

Laboratory results show that individual advanced ceramic proppant beads are much stronger than conventional ceramic proppant grains, and that the strength distribution is also much tighter than conventional ceramic proppants. The strength profile of the engineered beads bears a close relationship to the generation of conductivity-damaging crush fines. As a result, the conductivity measured in industry-standard tests is as much as 40% higher than that of conventional ceramic proppants, and this improvement is maintained over a wide range of closure stresses and multiple stress cycles. There is thus a critical link between individual proppant bead behavior and overall proppant pack performance.

Proppant transport in slickwater is a result of three major mechanisms: gravity settling (Stokes Law), sedimentation (dune formation), and saltation. The low density of advanced ceramic proppants reduces the settling rate, and the low coefficient of friction reduces the height of dunes, resulting in proppant transport further into the fracture.

An important new property related to proppant transport in slickwater has been identified, i.e., the coefficient of restitution. A high coefficient of restitution reduces clustered settling, and results in more active saltation. A new laboratory test to compare the coefficient of restitution of different proppants has been developed. In this test, advanced ceramic proppant beads typically move approximately 40% further than conventional ceramic particles, and twice as far as sand.

A comprehensive field test of Advanced Ceramic Proppants was performed in the Permian Basin. Ten pairs of wells were selected and the new material was pumped into one member of each pair, while conventional ceramic proppant was used in the other. Advanced Ceramic Proppant increased cumulative 12-month oil production by 20% compared to the offset wells. The statistical techniques which demonstrate this improvement also identified some key variables which impacted production, including stimulation treatment execution and interference effects.

The use of Advanced Ceramic Proppant increased the NPV of the wells by 25% relative to conventional ceramic proppant, and the incremental cost of the treatment was paid back in 3 to 4 months.
Feasibility and Challenge of Quantitative Cement Evaluation with LWD Sonic
Authors: Kinoshita Toshihiro , Izuhara Wataru , Valero Henri-Pierre , Blyth Matthew
Published: June 2014

Cementing is an essential part of well construction as it supports the casing and provides hydraulic sealing. Quantitative cement evaluation is becoming increasingly important in the industry to verify well integrity and zonal isolation. Such information has historically been obtained with a wireline tool, acquiring data at ultrasonic or sonic frequencies. The most common log providing information on cement bond quality is the cement bond log (CBL), which relies on the amplitude of the casing arrival to determine the quality of cement bonding to the casing and in some applications to the formation.

Although logging while drilling (LWD) sonic technology has progressed rapidly in recent years the established service from an LWD sonic tool that provides cement information is only top of cement (TOC), and it indicates only the presence or absence of cement behind the casing. Since the major structural part of the tool is a rigid steel collar, there is significant acoustic propagation along the collar. It is technically difficult to separate the casing signal from the one traveling in the collar as these two propagations have similar speed and frequency content. When the cement is poorly bonded to the casing, the casing amplitude can be far larger than the collar arrival. However, if the cement is well-bonded, most of the casing signal energy is dissipated into the cement, and the casing amplitude at a receiver a certain distance from the transmitter tends to be similar or even smaller than the collar arrival. In such cases, the measured signal loses sensitivity to cement bonding. However, it is challenging to establish a relationship between the respective amplitudes of the collar and casing as it depends upon many factors such as the acoustic impedance of the cement and the casing size.

We explore the feasibility of quantitative cement evaluation with a conventional LWD sonic tool. Finite-difference method (FDM) modeling over a wide range of conditions was conducted to quantify the relationship between casing amplitude and collar arrival. Results indicate that quantitative cement evaluation is feasible with existing LWD sonic tools, depending upon the bonding value. This study also provided information for comparisons between conventional wireline cement evaluation methods and LWD-derived CBL.
Smart Collaboration for Decision Making in Drilling
Authors: Fjellheim R..
Published: June 2014

In spite of impressive advances in drilling technology, the cost of drilling is soaring and represents a significant and increasing part of oil recovery investments. Data is available in abundance, but drilling teams are struggling to make sense and good use of the data in daily operations and decision making. By embedding analytics and decision making tools in "smart collaboration" solutions, we can make better use of scarce human expertise, help improve operational performance, and ensure compliance to safety standards.

We describe an implementation of smart collaboration for drilling. The solution supports decision making in a decentralized and multi-disciplinary team of engineers drilling complex wells in a large and mature offshore field. The system aids the team in carrying out challenging coordination and decision tasks in drilling, and is based on social media technology, mathematical decision models, and data visualization. Probabilistic decision models have been developed for a range of typical drilling problems, e.g. change bit, set casing, gas influx, etc.

Social media similar to the blogging and chatting tools we use in our private lives help team members to quickly obtain expert support, achieve a common situation understanding, and rapidly converge on a sound decision in complex drilling situations. Our solution combines high-level visualization of drilling status, risk and progress with problem-specific decision tools, all based on a common social collaboration platform integrated with the existing industry standard IT infrastructure of the operator company.
Automated Workflows to Monitor, Diagnose, Optimize, and Perform Multi-Scenario Forecasts of Waterflooding in Low-Permeability Carbonate Reservoirs (a KwIDF Project)
Authors: Ranjan P.. , Carvajal G. A. , Khan H.. , Vellanki R.. , Saputelli L.. , Md Adan F.. , Villamizar M.. , Knabe S.. , Rodriguez J.. , Al-Jasmi A.. , Nasr H.. , Al-Saad B.. , Pattak A..
Published: June 2014

Surveillance and optimization of waterfloods in low-permeability carbonate reservoirs pose many challenges. Updating reservoir models is tedious and time-consuming, involving multiple data sources, model updates, and simulations. Technological challenges include large simulation models, waterflood complexities, and limited real-time data. Human challenges must be addressed as well, since waterflooding decisions affect multiple disciplines: reservoir engineers, production engineers, facilities engineers, IT, Operations, and asset managers. The ‘languages’ and interests of these disciplines are quite different; necessitating a workflow that satisfies the needs of all disciplines and integrates people, processes, and technology.

This paper presents an innovative automated workflow to enable monitoring, diagnostics, forecasting, and optimization of waterflooding processes in days instead of weeks. This workflow seamlessly captures historical and monthly real-time data, updates simulation history, creates simulation restart prediction points, runs numerical simulations with optimization scenarios, selects the global optimum solution by scenario, and compares results so that multi-disciplinary teams can make reactive or proactive decisions to maximize short-term oil rates and long-term oil recovery, while honoring constraints on voidage replacement ratios, reservoir pressure, sweep efficiencies, production, and injection.

The workflow automatically updates real-time production data in the simulator each month. A base case is run to recalculate waterflooding indicators. The process then starts a 24-month production forecast, running hundreds of scenarios under constrained optimization to achieve global optimization points. The optimizer changes control variables such as injection volumes, tubing head pressure, bottomhole pressure, and production allowable. The workflow ranks potential well decisions with important impacts on oil rate and water cut.

The workflow uses an intuitive user interface incorporating the needs of multiple engineering and operations disciplines, and facilitates one common language while evaluating and optimizing waterfloods. This workflow has been implemented for a waterflood in a Middle East carbonate reservoir to help engineers evaluate the waterflood and make better, faster decisions.
Inflow Control Devices Improve Production in Heavy Oil Wells
Authors: Least Brandon , Greci Stephen , Konopczynski Mike , Thornton Kim
Published: June 2014

In order to maximize oil production, it is desirable to have a balanced influx of oil from the entire completion. Non-uniform production rates from each zone along the completion may not be evident early in the well’s production life, but they can become problematic when water and gas break through. If water and gas break through in select zones, they will produce at higher rates than the oil, which in turn will impede oil production rates from the remaining zones.

Formation permeability variations or toe-to-heel friction loss can cause flow rate differences between zones, and in a heavy-oil well, these variations may be even greater. Viscous fluids experience larger frictional losses both in the formation and the wellbore flow conduit; thus, when low viscosity water or gas breaks through, the flow from a high water or gas cut zone can quickly dominate the flow from the well. Inflow Control Devices (ICDs) have been developed to balance the influx of oil by creating additional back-pressure in the zones that produce at higher rates. Using ICDs can delay water or gas breakthrough, but once unwanted fluids break through, conventional passive ICDs are not able to maintain the balanced flow.

This paper discusses a new ICD, an autonomous inflow control device (AICD), which performs similar to a passive ICD during oil production and can be used to balance reservoir influx. Unlike passive ICDs, when unwanted fluids (water, gas) flow through the AICD, they take a different path than oil, and a much higher pressure drop is created. This behavior can be used to restrict the flow of unwanted fluids when they break through in a zone, allowing the oil production from other zones in a well to continue at the maximum rate.

Simulations are presented that will compare a stand-alone screen completion to a completion with passive ICDs, to a completion with an autonomous ICD. The simulation results will show a clear distinction in each type of completion, and it will highlight the benefits that are provided with the ICD and the even greater benefits derived from use of the AICD, both onshore and offshore.
Real Time Data: Interactive Monitoring of Data Flow for Continuous and Reliable Data Transmission
Authors: Al-Amer Abdulrahman A. , Al-Gosayir Muhammad , Al-Naser Naser , Al-Towaileb Hussain
Published: June 2014

The dependency on well-head and field real time data has significantly increased in the past few years in the oil and gas industry. The data is used to maximize oil and gas recovery, increase revenue and improve health and safety. This new mode of operation mandates the availability of reliable real time information sent by the different well and field digital equipment for optimum right-time decision making. The challenge is in the fact that intelligent field components include many different layers and nodes that increase the complexity of such assurance. Therefore, the health and the data transmitted from these components, such as digital gauges (e.g., multi-phase flow meters and permanent downhole monitoring systems) and the communication network must be continuously monitored and well maintained.

This paper will highlight a newly developed comprehensive and interactive monitoring and key performance indices reporting solution to quantify, assess and visualize the health of the different intelligent field components. The new system is using advance technologies, such as GIS maps to locate fields, equipment, real-time data historian servers, and networks to highlight their availability and reliability status. This solution provides real time alerting and alarming in case of transmission failure, well data integrity situation or inaccurate data detected using an automated diagnostic engine, thereby maximizing safety and increasing accuracy and data reliability.
Profit and Loss at the Wellhead; Producing from the Wells that are Profitable and Shutting-in the Loss-makers
Authors: Forrester Dean , Trescott Jenna M. , Nell Johan , Landgren Ken
Published: June 2014

In traditional Digital Oilfield programs, it is assumed that increasing production from any given well has a positive impact on the operator’s bottom-line. In fact, optimum profitability for a field is dependent not just on production volume, but also on the individual contribution of each well to the overall profitability of the organization.

Understanding the contribution of each well, and operating based on this knowledge, can provide significant benefits over and above traditional production optimization techniques. Specifically, it can allow the field operations team to prioritize highest profitability wells – rather than just highest flow wells – and can even allow the identification of seemingly ‘productive’ wells which actually have an overall negative contribution to the organizations bottom line.

To calculate well –by-well profitability, operators must not only be able to accurately measure/allocate production volume, but must also consider other factors such as water handling cost, ongoing maintenance cost, production sharing agreement impact, short and long-term pricing contracts, etc. These and many other factors all contribute to the financial benefits accrued from a given well.

Understanding the contribution of any well or group of to the profitability of an operator is therefore more complex than simply calculating the production flow for the day and multiplying by the prevailing price for WTI or Brent.

The data necessary to calculate well-by-well contribution is spread across many siloed systems, including production, maintenance and financial applications. At best, operators review production volumes monthly to produce revenue figures when some sort of contribution figure may be possible to calculate. However it rare for any operator to manage cost information at the resolution necessary to calculate P&L accurately, so there has not been the ability to manage daily operations based on well-by-well profitability. Instead, operators have typically calculated a broad ‘field lifting cost’ and applied this across wells.

Clearly, with the high-well counts and heterogeneous production fields that are increasingly common, the potential value to manage wells on a full fiscal calculation rather than just cost can offer significant benefits.

This paper discusses the main contributing factors to well profitability, the potential business value from operating on well- P&L versus traditional volume-based approaches and describes solutions to achieve this capability.
Integrated Operations Implementation in Samarang Field
Authors: Abdul Razak Chik Adnan , Sayung Colinus Lajim , Ahmad M Zul , Wong Lee Hin , Muhamed Salim Muzahidin , Mohd Som Mohamad Kasim
Published: June 2014

Increased demand in production and recovery, advancements in technologies and the desire to collaborate expertise across multiple assets are changing the work process at many oil and gas companies. Integrated Operations (IO) program describes the process, performance improvement and transformation of Petronas Carigali (PCSB) production operations. The program aims to help PCSB to address growth, organization and environmental challenges by integrating new transformational technologies with streamlined work processes and enables the followings: Enables a more effective working environmentWork processes are streamlined and automatedQuality information is available and accessible across the organizationCollaborative expertise of multiple locations, teams and domains across distanceIntelligent alarms and alerts for continuous asset awarenessIncrease hydrocarbon production and recovery

Samarang was the first field selected for end-to-end asset management IO project. Its implementation deliver objective and focus at the whole of the asset operation optimization through providing increasing levels of monitoring and surveillance, diagnosis, optimization and operations transformation in a way that fits PCSB's current IO state as well as future expansion plans.

The case study has shown following benefits since its inception in 2011: An innovative parallel design process was invented to improve the efficiency and integrity of the design processAn Integrated Operations model was described and defined for framing, planning, design and execution of the projectHeightened monitoring and surveillance through installation and retrofitting of measurements and control devicesIntroduction of "Functional Base with Asset Mindset" collaborative working environment across multiple locations, team and domainsTotal asset optimization hybrid of steady-state and transient-state optimizationProduction enhancement and reserve improvement based workflows

The goal of this paper is to describe the IO framework and underscore its benefits that can be drawn from the Samarang IO implementation.
Remote Field Management of Greenfield Assets in Australia and East Timor: Delivering Value by Automated Production Surveillance and Optimization Platform
Authors: Biniwale Shripad , Trivedi Rajesh , Tran Andrew , Derrij Joseph , Yokote Ryosuke
Published: June 2014

Eni Australia is operating the Blacktip gas field offshore Australia and Kitan oil field offshore East Timor. The main challenge was to manage these green fields remotely, with lean resources and strict deadlines covering tasks like data capture and acquisition, data validation, application integration and field analysis efficiently. The implications of the decisions made during the development of a green field are imperative to the optimization of reservoir production. Therefore, an integrated production decision support system was required for performance monitoring of asset health and optimizing production to meet the targets.

This paper describes how these challenges were overcome at Eni Australia by centralizing the operations of both fields into a standardized production platform, providing a seamless data transfer from offshore assets to the onshore technical office and establishing the foundation towards a digital oilfield. The platform framework automates the process of acquisition, transfer, conditioning, aggregation and storage of production and operations data into a secure centralized data repository with an auditable amendment history. The production platform provides improved operational and reservoir visibility, which forms the basis for all subsequent analysis and underpins the engineering justification to support operational decisions.

The current solution framework provides a multifunctioning system that can be expanded for future assets and fields as they come online by leveraging the investment in the existing system. All the domain experts, from production operations to reservoir engineering, will have the required information at their fingertips for collaborative decision making. Thus, a centralized production platform provides engineers with an improved field visibility for remote field management, proactive decision making and help them to strategically develop fields by optimizing production.
Field Management by Proactive Optimisation of Intelligent Wells - A Practical Approach
Authors: Haghighat Sefat Morteza , Muradov Khafiz , Davies David
Published: June 2014

Intelligent wells (I-wells) are one of the core elements of the "digital oil field". Numerous publications have described their ability to simultaneously increase recovery and "Add Value". Maximum "Added-Value" is achieved via operation of the wells’ zonal flow-control valves in a manner that respects the field’s optimisation objectives at both a Well (short-term, Reactive control) and a Reservoir (long-term, Proactive control) level.

Relatively simple, well-proven algorithms are available for Reactive (mainly well out-flow) control. By contrast, techniques for Proactive control (or reservoir fluid front displacement management) are much less mature; despite them being capable of delivering greater "Added-Value" in many reservoir scenarios. Coupling Genetic Algorithms (GA) with a commercial reservoir simulator is the most commonly used Proactive optimisation technique (Alghareeb et al., 2009, Almeida et al., 2010, Pinto et al., 2012). However, GA has not achieved universal acceptance since, like many other optimisation algorithms, it either fails to find the maximum production improvement and/or requires excessive computational time and resources due to the large number of control variables associated with the optimisation process.

This paper discusses the use of the parallel Simultaneous Perturbation Stochastic Approximation (SPSA) algorithm for Proactive optimisation of an I-well in a simplified, real field. The algorithm’s parallel processing capability speeds-up the optimisation process when appropriately employed with a commercial reservoir simulator. A properly tuned SPSA algorithm was found to rapidly converge to a near optimum solution. Algorithm tuning by the engineer was shown to be aided by use of a novel, multi-dimensional, projection scheme to visualise the algorithm’s performance and monitor its progress towards the global optimum solution.

Computationally, SPSA is significantly faster (3 – 5 times in the examples tested to-date) than GA. This decrease in processing time can significantly increase the practicality of introducing proactive optimisation for large real field models on a routine basis where it is used alongside the more commonly applied reactive control strategy for managing the individual well performance (Yeten et al., 2002, Grebenkin and Davies, 2012).
Real-time Evaluation of Acid Stimulation Performance in Extended-Reach Carbonate Wells with DTS-enabled Intelligent Completions
Authors: Wang Xiaowei , Bussear Terry R.
Published: June 2014

Our industry has long searched for a means of evaluating the efficacy of acid stimulation of extended reach carbonate wells. Intelligent completion architectures and technologies have enabled the pre-compartmentalization of these wells, and delivered the means to selectively and remotely control zonal inflow/outflow along with the ability to make real-time measurements within these zones. This paper describes the development and in-well usage of a unique modeling technique combined with a Distributed Temperature Sensing (DTS)-enabled intelligent completion system to evaluate the coverage and effectiveness of intra-zonal acid stimulation.

This system leverages a proprietary thermal model that accounts for three in-well thermal effects occurring during compartmentalized bull-head treatments. The technique quantitatively evaluates the acid distribution and acid-rock interaction in each treated zone. The acid distribution measurement can be generated immediately following the acid treatment, enabling real-time determination of the acid volume and its distribution within the target completion interval(s). The operator can then decide if retreatment(s) is needed.

The paper focuses on the modeling technique for matrix acid stimulation in which acid is delivered by bull-heading down the tubing string to each pre-compartmentalized zone where sliding sleeves have been positioned at the lower end of each zone. The flow of acid into the tubing/perforated-casing annulus thus produces a counter-flow condition (within the annular space) to reach all perforations within that respective zone. A direct measurement of acid movement and placement is immediately generated based on a full-length DTS measurement within each zone during treatment. The paper also demonstrates the capability of the system in the generation of a type-curve. The operator can then qualitatively identify the under-treated or over-treated sections by comparing the DTS measurement results to the type-curve. A synthetic case study is used to demonstrate the technique. Full field applications using this model will be discussed in a future paper.
Bringing ESP Optimization to the Digital Oil Field: Rockies Field (USA) Case Studies
Authors: Ratcliff Dustin , Cetkovic Ivan , Gomez Cesar
Published: June 2014

Marathon Oil operates several brownfields in the Rockies, most of which are approaching an operating life of 100 years. To optimize the production from these mature fields, Marathon Oil is implementing several technology upgrades under the banner of the digital oil field—using information technology innovations to better monitor, record and analyze field data for faster and more informed optimization decisions.

One area receiving particular focus is the artificial lift method of electrical submersible pumps (ESPs). In 2010 Marathon Oil began installing downhole sensors in all ESP wells that were pulled for either a failure or a workover and downloading the data into an ESP real-time monitoring, diagnosis and analysis software system. The system brings intelligence to ESP operations by monitoring pump data from each well in real time, and collecting this data in a central location. The operator can then select from different software tools—also centrally located—to analyze the information, verify ESP operation within required parameters and if necessary, decide how to change the operating parameters to improve pump performance and boost production. The system also can be set with alarm capabilities to provide real-time notification of a problem.

The intelligent capabilities of the system plugged into Marathon Oil’s digital oilfield architecture help field engineers work smarter and more efficiently. Instead of spending needless hours travelling from field to field to monitor pump performance, engineers are notified of problems early and receive instant verification of field performance. The system minimizes nonproductive time (NPT) and frees up the field crews to work on other projects designed to increase production.

This paper provides several case studies that highlight through a digital oilfield solution how an intelligent ESP-optimization option is identifying problems early and extending the economic production life of Marathon Oil’s mature fields in the Rocky Mountain (Rockies) region of the United States (US). At the time of this paper, Marathon Oil installed downhole sensors in more than 430 of its 770 ESP wells, which are all presently being monitored via the ESP real-time monitoring and analysis program. Within this short period of real-time monitoring, Marathon Oil has realized production gains of over 700 Barrels of Oil per Day (BOPD) in one of the fields.
The Process Control Aspects for Well Head Control
Authors: AL-Mawali Salim
Published: June 2014

Feedback control is not new in the Exploration and Production (EP) industry. Almost all the units in a hydrocarbon production station are controlled with an automatic controller of some sort. However, the above statement does not hold true for any equipment outside the boundaries of production stations such as production wells and injection wells. The aim of this paper is to focus on an area that has been for a long time considered outside the process control engineering domain. Driven by positive trials with clear demonstrated benefits, this picture is changing at Petroleum Development Oman (PDO). This paper will show how simple control schemes are having a great impact on PDO’s oil production optimization and gas constraint reduction with the minimum of cost. The paper will present two utilizations of such control schemes and how much value PDO is reaping from these two implementations. The first is employed on production wells that exhibit an unstable behavior and the other is used for water injection systems. Finally, the challenges facing these technologies are discussed.
Model-Driven Development for Safety-Critical Projects in Intelligent Energy
Authors: Fechtelkotter Paul , Bleakley Graham , Douglass Bruce Powel , Amaba Ben
Published: June 2014

A responsive organization is one whose engineering processes and platform can sense and respond with flexibility, accuracy, precision, and speed to macro trends impacting the energy industry, including increased complexity, rapid adoption of new technologies, increasing use of Engineering, Procurement and Contract Management (EPCM) companies, modularity, internationalization of supply chains, and new regulatory mandates, while constantly improving operations and capital efficiency. IBM has developed an engineering approach and platform that will improve the transformation to Digital Intelligent Energy. The approach and platform reuses best practices harvested from adjacent complex, safety-critical industries. This paper describes Model-Driven Development (MDD) for Safety-Critical Projects using analysis and assessment of instrumentation, control and embedded technologies.

MDD allows organizations to first analyze problems and then derive and evaluate potential solutions using various analytical techniques, including simulation, prior to final decision-making. Stakeholder needs are verified and validated in a formal manner, creating a common understanding of the requirements. Graphical representations of the requirements improve communication by breaking down barriers between domains, better aligning the process and organization as understanding between the domains improves. This reduces the number of issues encountered when commissioning an asset, leading to reductions in cost and schedule risk. This approach has been applied successfully in many safety critical industries, including aerospace, defense, nuclear, automotive and medical devices.

IBM has been successful in helping companies manage through this change process and has codified our knowledge in a series of best practices applicable to any organization. Working in a strong partnership with the organization, our approach is to first understand the capabilities of the organization, how it operates, and then extends the analysis to its future needs, resulting in a roadmap for the transformation from the current practices to the future state. By leveraging this approach, we have changed the operating philosophy of many companies, improving their efficiency, effectiveness, and profitability.