bluuebunny/crossref_metadata_2025 huggingface dataset:
How to Cope with some of the Challenges Associated with Laboratory Measurements on Gas Shale Core Samples
Authors: Lalanne B.. , Le-Bihan A.. , Elias R.. , Poyol E.. , Martinez L..
Published: June 2014

Routine lab characterization of conventional cores is often limited to geology, petrophysics, and mineralogy. With gas shale plays, however, geochemistry and rock-mechanic are key parameters to characterize as well. In this paper, we present several innovative techniques which allow coping with challenges associated with lab characterization on gas shale core samples.

Such alternative techniques need addressing the following issues: Complex lab measurements, potentially to the threshold of what routine lab devices can characterize.Potentially high vertical variability of mineralogy and organic content.

Two innovative and worldwide unique measurement devices have then been developed in-house: A transient permeameter, the Step-Decay device, capable of measuring permeability down to the nanoDarcy, at different levels of confining stress and connate water content.A high-resolution geochemical core logging tool, the LIPS device (Laser Induced Pyrolysis System), designed to measure the organic matter content on a continuous centimeter scale basis.

So as to cope with the variability issue, a comprehensive set of high resolution core logs has been systematically run: CT-scan and spectral GR logs for petrophysics, scratch-test log for rock-mechanic, and LIPS log for organic matter quantification; we combine all these techniques together for a better core characterization.

We present the analysis workflow applied to a gas shale case-study, insisting on the challenges we faced and the way we coped with them. Benchmarking with alternative techniques and lab results is presented as well.
Numerical Simulation of Low Permeability Unconventional Gas Reservoirs
Authors: Ding Didier Yu , Farah Nicolas , Bourbiaux Bernard , Wu Yu-Shu , Wang Cong
Published: June 2014

Unconventional gas resources from tight sand and shale gas reservoirs have received great attention in the past decade and become the focus of the petroleum industry as well as energy resources worldwide, because of their large reserves as well as technical advances in developing unconventional resources. Compared to conventional reservoirs, gas production in ultra-low-permeability unconventional reservoirs is driven by highly non-linear flow equations and involves many coexisting processes due to the presence of multi-scale fracture networks, and to the heterogeneous nature of a porous/fractured and stress-sensitive rock. Therefore, quantifying flow in unconventional gas reservoirs remains a significant challenge.

In this paper, we discuss a mathematical model and a numerical approach for simulating the production of unconventional gas reservoirs, in order to assess well performance and understand the critical parameters that affect gas recovery. Specifically, we consider the flow behavior in a stimulated reservoir volume (SRV) including a tight matrix and multi-scale fracture networks, namely primary hydraulic fractures, induced secondary fractures and micro-fractures. The feasibility and the limits in the use of single-porosity or dual-porosity reservoir models to simulate gas flow in such a system are discussed, and a multi-porosity approach is evaluated. The impacts of various physics related to unconventional gas reservoirs, such as adsorption/desorption, Klinkenberg and geomechanical effects, are quantified.

This work helps to improve simulation technologies for low-permeability unconventional gas reservoirs. An appropriate modeling approach actually underlies effective simulation tools for quantitative studies of unconventional reservoir dynamics and performance, taking into account multi-scale fracture impacts on gas production, well and stimulation design, and optimal production schedules in field development.
Origins and Integrated Exploration of Sweet Spots in Carbonate and Shale Oil-Gas Bearing Reservoirs of the Timan-Pechora Basin
Authors: Petukhov A. V. , Kuklin A. I. , Petukhov A. A. , Vasquez Cardenas L. C. , Roschin P. V.
Published: June 2014

Hydrocarbon exploration in carbonate and shale deposits seems to be less efficient than exploration of terrigenous reservoirs in the Timan-Pechora Basin. This disparity is due to a number of factors, chief of which are complexity of geological structure in areas of carbonate and shale reservoirs and complexity and unpredictability of porosity and permeability. Therefore, considerable heterogeneity of carbonate and shale reservoirs reduces efficiency of prospecting, exploration and engineering of oil deposits in carbonate reservoirs.

The study of carbonate and shale reservoirs, which formed in different periods in the Timan-Pechora Basin, has highlighted importance of tectonic fractures in the evolution of complex reservoirs. These fractures are formed during local tectonic folding. The pervasive faults and fractures generated during these folding episodes in carbonate and shale rocks promote active filtration and leaching by surface and subsurface waters, containing corrosive components (CO2, H2S, etc.). Highly permeable fracture zones, which are called sweet spots, affect the processes of hydrocarbon migration and oil-gas accumulation. Exploitation experience at Usinsk, Kharyaga, Upper Vozey and other oil fields has shown, that sweet spots influence processes of oil pool formation. It is necessary to take into consideration such sweet spots when the optimal system of reservoir engineering is chosen. An integrated exploration method has been developed for finding and delineation of sweet spots. This method includes analisys of seismic and gravity exploration data, aero-space photo-interpretation, well logging data, results of core and drilling data interpretation.

The use of integrated exploration is proven to be effective in finding sweet spots in carbonate and shale reservoirs. It has also enabled greater understanding of the complexities, geometry, and tectonic relationships of sweet spots formation.
Integrated Unconventional Gas Evaluation Workflow: from Anisotropic Geomechanical Modelling to Completion Design
Authors: De Gennaro V.. , Amri R.. , Brignoli M.. , Kallel N.. , Wielemaker E.. , El Ayeb S..
Published: June 2014

Emerging unconventional exploration targets in North Africa are gaining increasing attention. Experience gained over the past two decades on unconventional gas reservoirs (e.g., tight sands, gas shales) has demonstrated that viable economics for unconventional resource plays can only be met if reserves are proved (reservoir quality) and producible (completion quality). With the reservoir quality identified, improved productivity in ultra-low-permeability unconventional reservoirs requires extensive hydraulic fracturing treatment to maximize contact area and unlock resources.

North Africa geological settings represent a challenging environment for effective hydraulic fracturing design. Deep reservoir targets, active tectonics and simultaneous occurrence of heterogeneous rock properties (including isotropic and anisotropic behavior) constitute a unique endeavor for a correct geomechanical modeling and a reliable assessment of closure pressures and fracture containment as input for hydraulic fracturing design.

This paper describes the implementation of an integrated unconventional evaluation workflow adopted for the completion design and hydraulic fracturing of a vertical well in tight sands and gas shales. A data acquisition program for tight formations was implemented to ensure full integration of logs data and core data from laboratory testing. Anisotropic measurements from an advanced borehole sonic logging tool and laboratory geomechanical tests were used to characterize the mechanical behavior of the reservoir lithological units, showing high degree of mechanical anisotropy in Silurian shales and Ordovician clayey horizons. Since isotropic assumptions predict inaccurate stress magnitudes and lead to significant error in stress contrast, the use of anisotropic-based geomechanical modeling is emphasized with regard to wellbore stability analysis and completion design. The integrated workflow involving anisotropic stress modeling allowed addressing and solving open issues related to wellbore failure prediction and estimation of hydraulic fracture containment.

For completion design purpose a comparison between different assumptions in terms of geomechanical input and hydraulic fracturing stimulation outputs is presented. The influence of the two different stress models (i.e. isotropic and anisotropic) is discussed. The effect on fracture geometry of the anisotropic clay layers, commonly treated as purely isotropic, is emphasized. It is shown that the hydraulic fracture in tight sands stays more contained in the reservoir target providing a better reservoir contact and optimum completion due to the higher minimum horizontal stress predicted by the anisotropic model in the clayey intervals.
Adaptation of Successful Tight-oil Stimulation Technique in Unconventional Resource Play in Western Siberia
Authors: Kaluder Zdenko , Nikolaev Maxim , Davidenko Igor , Leskin Fedor , Martynov Mikhail , Chong K. K. , Prokhorov Alexey , Shnitko Andrey , Fedorenko Evgeny
Published: June 2014

Application of horizontal multiple-stage fracturing is becoming the standard completion technique for oil and gas developments both in shale and tight sands. This technology has proven to be a game-changer within the US oil and gas industry to the point of creating an oversupply of gas in the US. Predictions indicate that the supply of oil related to this technology could allow the US to become self-sufficient within the decade. Globally, shale and tight-sand exploration activities are also increasing. This concept was successfully suited for and applied within a Russian tight-oil play in the Em-Egovskoe license area in western Siberia.

This paper provides the case history of how a horizontal multiple-fracturing completion methodology helped unlock the potential reserves in the western Siberian Em-Egovskoe tight oil field. This very heterogeneous and lenticular sand oil play was known for years for its complexity and arduous nature. The completion technique employed a proven North America multiple-stage fracturing technique using a combination of swellable packers and sliding-sleeve frac ports. The fracturing design for the Em-Egovskoe field is discussed. This design is an adaptation of an alternating hybrid fluid system composed of proppant slugs during the pad stage and a high-concentration proppant ramp in the main frac stage.

The well is currently flowing at commercial rates synonymous with early production in a typical North American oil shale well. The various monitoring techniques for measuring fracturing efficiency are also discussed. A production curve fit analysis using early production data allowed the operator to evaluate how the project was being commercially realized. Results and recommendations are presented.
Rigless Operation to Restore Wellbore Integrity using Synthetic-based Resin Sealants
Authors: Jones P. J. , Karcher J. D. , Ruch A.. , Beamer A.. , Smit P.. , Hines S.. , Olson M. R. , Day D..
Published: June 2014

Sound wellbore construction and maintenance are essential to the successful development and production of hydrocarbons from unconventional resources. During the development of a Polish shale play near the Ukrainian border, the integrity of a well under construction became compromised resulting from a breach in an external casing packer on the production string. Successful completion of this well could require fracture-stimulation operations at pressures up to 9,000 psi, which would be impossible, unless the breach could be repaired. A cementing valve just above the breached packer had already reduced the inside diameter (ID) of the 4 1/2-in. production string to 3.827 in. The difficulty of running a casing patch in this restricted environment and the further diameter reductions eliminated this option from being a preferred solution. In addition, the high pressures associated with fracturing operations warranted an innovative solution, rather than a conventional approach. Recently commercialized resins have displayed the ability to withstand stresses higher than 10,000 psi and compressive strains greater than 40% without failure. However, case histories on field deployment of these materials, their ability to be drilled, and performance after hydraulic fracturing were essentially non-existent. This paper presents a case history on the laboratory development of a customized resin solution, the rigless operation using coiled tubing (CT) to place the materials and repair the breached packer, and the drillout after placement. Effectiveness of the remedial operation was determined by subsequent pressure testing. After restoring wellbore integrity, hydraulic fracturing operations were completed and successful production from this well began.
Case Study—Investigating Probable Root Causes Behind Consistent Higher Water Cut in a Mother CBM Well than its Deviated Wells: Well Spacing, Well Stimulation, and Overlying Strata Viewpoints and Recommendations
Authors: Chandra Sreerama , Adil Faraaz
Published: June 2014

Production from coalbed methane (CBM) reservoirs can often be challenging, particularly related to the dewatering process. Improper positioning and completion of wells can lead to increased complications during the production phase. Additionally, consistently high water levels (undeclined static reservoir pressure) can impede gas production. This paper describes well and production information from the Raniganj coal block.

The pad completion discussed has a mother vertical well (V-well) in which three main coal seams were completed (of the total five main seams with interspersed local seams), and dewatering commenced in 2009. At the end of 2011, encircling the V-well, four deviated wells (D-wells) at different azimuths were positioned at horizontal closures of 263 to 364 m from the bottom seam of the V-Well, wherein five main coal seams, along with interspersed local seams, were completed and scheduled for dewatering in mid-2012. Despite consistent high water production rates from the V-Well, the water levels in the V-Well stood consistently higher (rising upward) than the water levels in the D-wells, unlike nearby V and D-well pads. Well spacing information, well stimulation plots, perforation plans, and overlying strata for all five wells on this pad were studied and conclusions were drawn. This paper discusses such conclusions as well as the analyses performed to understand these issues. An attempt has also been made to best optimize hydraulic fracturing (HF) treatment designs to obtain the maximum benefits from stimulation operations.

The results reported in this paper will influence the operator's cost optimization, which could be a major positive influence on the low-cost CBM market in addition to increasing efficiency of the entire operation.
Effect of Salt Concentration on Base-gel Viscosity of Different Polymers used in Stimulation Fluid Systems
Authors: Das Prasanta , Konale Sumit , Kothamasu Ramya
Published: June 2014

Most conventional and unconventional reservoirs use viscous fluid systems for hydraulic fracturing for various reasons, such as good proppant transport, less fluid loss, less pumping friction pressure, etc. Salt is often introduced as part of the fluid system for clay protection as well as to increase hydrostatic pressure, resulting in reduced surface pressure. This paper investigates the effect of salt concentration on reduced viscosity for different types of polymers used in fracturing fluids.

Different polymers, such as guar, hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar (CMHPG), carboxymethyl cellulose (CMC) and other biopolymers, are used for preparation of fracturing fluids. Aqueous solutions of these polymers become viscous gel on hydration. KCl salts at different concentrations were mixed with the different polymer gels at room temperature and the viscosity change was observed at a shear rate of 511sec-1. The effect of salt on the hydration rate was also observed at room temperature for the different polymers. A hydration time of up to 60 min was maintained. Plots with different polymers were compared at fixed salt concentrations to identify which polymers experienced more severe effects. It was observed that the CMC category fluids experienced a high reduction to viscosity with the salt content than other fluids. A chemical explanation is given to understand salt effects on different polymer structures.

Many offshore wells use seawater for preparation of fracturing fluids, which is known to contain high salt concentrations. Even drilling fluids use different polymers at various salt concentrations to increase cutting stability as well as mud weight. Formation water can also contain high salt content. When drilling or stimulation fluids mix with formation brine, a high reduction to viscosity can occur, resulting in poor proppant or cuttings transport. This study should aid the decision-making process when choosing polymers and adjusting viscosities considering salt effects.
Liquid-Rich Shale Versus Conventional Depletion Performance
Authors: Lei Guowen , Cheng Nan
Published: June 2014

This paper evaluates fundamental differences in depletion performance of wells producing from ultra-low permeability1 ("shale") reservoirs and wells producing from conventional reservoirs, with the ultimate goal of defining what differentiates "conventional" from "shale" performance. It attempts to answer the question – what permeability range defines "ultra-low" depletion performance and what permeability range defines "conventional" depletion performance – with the intermediate permeability range being a transition from ultra-low to conventional behavior. We "map" the transition from conventional depletion performance to "shale" depletion performance in terms of formation permeability.

In this study we compare depletion performance for reservoir permeabilities ranging from 10 nD to 100 md, with PVT, relative permeability functions, and other rock properties being the same for all simulation cases. Four reservoir fluid systems, ranging from rich gas condensate, near-critical oil to light oil, were used in this study. A one-section drainage area was used even though we are aware that shale resources are often developed with smaller well spacing (typically 80- or 160-acre strips, ~ one mile long).

Depletion performance of conventional gas condensate and oil reservoirs - where oil recovery and producing gas-oil ratio (GOR) are independent of permeability and flowing BHP, is valid for k > 0.1 md. At permeability levels of ~ 0.001 md (1000 nD) or less, the depletion performance of shale and ultra-tight reservoirs is characterized by that producing GOR is a strong function of flowing bottomhole pressure (BHP) and degree of undersaturation (Whitson and Sunjerga, 2012).

Our results from this study show that conventional reservoir performance, depending somewhat on the reservoir fluid system, is observed for k > 0.5 md, while ultra-tight "shale" performance is found for k < 1000 nD (0.001 md), with a gradual transition between these permeability values and shale-like depletion performance appearing already at 0.01md.
Unconventional Gas Water Management: What can be applied from Decades of Experience with Conventional Oil Produced Water Management?
Authors: Evans Robin
Published: June 2014

Shale gas wells can each require between 8,000 m3 and 16,000 m3 of frac water, with up to 25% of that water being returned to the surface during production. Effective asset life cycle water management is key to the technical and economic success of both unconventional gas and conventional oil developments. Unconventional gas resource development in densely populated Europe presents different frac water management challenges to those in sparsely populated areas of the USA.

How can decades of worldwide experience of onshore conventional oil produced water management be applied to improve water management for unconventional gas wells in the areas of: Sourcing frac water suppliesObtaining permits for water abstraction and disposalResolving stake holder environmental concernsInvestigating frac water related formation damageUnderstanding returned frac water compositionTreating and recycling frac waterMinimizing frac water requirements

Onshore water management for unconventional gas and conventional oil production are compared and contrasted with the objective of optimizing frac water life cycle management for unconventional gas resources in Europe.
Are Egos A Main Obstacle To Intelligent Energy Implementation - And Can We Get Around It?
Authors: Jeffery Karl
Published: June 2014

Most of the information in this paper is wrong.

I don’t plan to waste your time - I believe that I have useful ideas here which could make a big contribution to offshore safety.

But when the CEO of a Norwegian oilfield services company once said to me last year that ‘most people are wrong most of the time' – I thought, well he’s right in the sense that I can’t think of anyone who is right most of the time - and so that probably goes for me, too.

And I also want to make the point that, as reflective individuals, we do have the capacity to train our egos - and if we believe that egos are the source of many obstacles to achieving safety, perhaps we can solve the problem at source.

To start explaining what I mean, I would like to tell you about some talks which were presented at a breakfast forum at Offshore Europe in September 2013, about 2 weeks after the Sumburgh helicopter disaster in Scotland when 4 people lost their lives.

The speakers included Martin Rune Pedersen, MD, Maersk Oil UK; Judith Hackitt CBE, Chair of the UK's Health and Safety Executive; Ian Sharp, Chief Operating Officer, Fairfield Energy.

Mr Pedersen of Maersk explained that every time a new drilling rig is brought to Maersk, the company organises two day workshops with with the drilling company staff, including with team building exercises and technical discussions. Maersk values ‘humbleness’, which it says is "about listening and learning and giving space to others." It also values what it calls ‘uprightness’ – where people stick to their word.

Judith Hackitt advocated a mindset of ‘constant unease’, which "means never thinking the problem is fixed," she said. "Constant unease means never being complacent, being prepared to ask hard questions, and not seeking reassurance from what you know is right."

Meanwhile Ian Sharp, Chief Operating Officer, Fairfield Energy, presented a result of a survey into worker engagement in the North Sea -which showed expected results on first glance, but when you look at it more deeply some questions emerge- for example, why do site leaders feel less personally engaged in the site’s safety culture than workers do?

I am trying to pull out a common thread between all of these points - that all speakers were actually focussing on ego - a main threat to safety - and how to stop it causing problems and help us work more intelligently.

The ego which tells us that everything is fine when it isn’t, the ego which stops us questioning too hard, and the ego which arises in difficult personal discussions when we get defensive talking to people we don’t know very well.
Reducing Unplanned Loss Through Multifield Operations
Authors: Kjellsen Kristine
Published: June 2014

Unplanned loss is reduced on the Norwegian continental shelf (NCS) through using Multifield Operations. Multifield Operations entail an overall responsibility for maintaining the integrity of certain equipment through condition and project based maintenance. Tasks, responsibility and professional resources are organized in one unit for multiple installations. This allows for synergies and a unique experience transfer and establishment of best practice. Engineers, executing personnel, planners, condition monitoring, and follow up is gathered in one unit.

Through monitoring, they detect negative trends and errors in an early phase and maintenance carried out with resources that hold operational expertise in the certain discipline in a project based model. Work is planned and implemented in close collaboration with the installations, operations groups, other internal specialist groups and vendors in a proactive, planned and controlled manner. They manage both planned and unplanned work on the systems and equipment in a standardized way.

Most of the pre- and post-operational work is done onshore. Planning is essential to managing resources and prioritizing between tasks based on HSE and production criticality. Quality assurance and risk management is integrated in the planning process.

The paper will address how Multifield Operations are managed through principles of collaboration technology and understanding human factors. The paper has been developed through field analyses. The Multifield Operations model has been applied to rotating machinery, fiscal metering, telecommunication as well as safety and automation systems on more than 29 installations. The model is of great use both to other operators as well as a multitude of related stakeholders and disciplines.

Multifield Operations contribute to a substantial reduction in unplanned production loss. The Multifield Operations model allows the company to plan approximately 1000 maintenance and improvement campaigns across 29 installations yearly, 80% as delivered on plan, with a serious incident frequency (SIF) of zero and they receive positive "client" feedback on their customer satisfaction survey. In addition they complete more work with less resources by gathering and using them across installations.

Multifield Operations may be the best sustainable option in a market where resources are getting scarcer and production moves deeper and colder by the year. It requires smarter and increasingly automated ways of operating. Multifield Operations contribution is a holistic approach to condition and project based maintenance.
Optimal Well Work-over Scheduling: Application of Intelligent Well Control Optimisation Technology to Conventional Wells
Authors: Zarei Faraj , Muradov Khafiz , Davies David
Published: June 2014

The installation of intelligent well completions is often justified by the technology’s ability to manage zonal inflow remotely with the consequent reduction in the well intervention frequency. A range of well and field production optimisation techniques that screen all possible zonal flow-management actions have been developed to control and optimise such intelligent wells and fields. This paper sets out to explore whether such techniques can be extended to provide an optimised work-over schedule for an oil field developed with conventional wells.

Published work-over schedule methods typically rely on well screening and ranking algorithms that are based on the current production performance of the well(s) being considered. This approach, which reacts to the current production situation, may lead to sub-optimal solutions due to the omission of work-overs which may not be the highest ranked at the time of implementation, but could prove to be more profitable in the longer term.

This study develops a workflow to design a proactive, work-over optimisation workflow using Genetic Algorithms (GA). It is based on an integrated, economic simulation model of the field which includes both the direct and the indirect costs associated with well interventions. The paper explores whether a "steered" GA created by the addition of screening and advanced sampling methods to a "pure" GA provides sufficient simplification of the problem to make it suitable for routine use in the field. Problem formulation and variable definition is discussed, allowing the inclusion of field knowledge to reduce the search space and steer the optimiser. The advantages of this modified GA are quantified by comparing it with the performance of the "pure" GA optimisation approach to the problem.

A significant added field value was achieved by the "steered" GA when compared with the "pure" GA.
A Smart Flow for SmartWells: Reactive and Proactive Modes
Authors: Carvajal G. A. , Boisvert I. , Knabe S.
Published: June 2014

Interval Control Valves (ICVs) are important tools for managing production challenges such as localized water or gas breakthrough, particularly in multilateral wells and horizontal wells with open-hole completions. This paper describes an automated workflow designed exclusively for wells with intelligent completions that use ICVs and real-time sensors for both down-hole and surface data. The workflow was designed to provide right-time production monitoring, well diagnostics, and ICV optimization for those intelligent wells equipped with ICV and multiple downhole pressure and temperature sensors.

The automated workflow performs several tasks: collect and condition production data, provide local history matching, generate several optimization iterations to estimate the best valve setting, and use numerical simulation to generate a number of scenarios where the ICV positions are changed over simulation time. To perform these tasks, the workflow models fluid mechanics between the ICV and a heterogeneous reservoir using next generation software such as steady-state hydraulic applications and a numerical simulator that accounts for the ICV settings. Tracking and visualization of streamline trajectories was used to add value of optimization process particularly the calculation of well distribution factors.

The horizontal well in this study has 5 ICVs positioned at different locations. The reservoir model is dual porosity-dual permeability. Local Grid Refinement (LGR) is used to model the horizontal section. The reservoir is subjected to a waterflooding process with more than 10 years of history. Two injectors are associated with a horizontal producer.

The workflow operates in two ways: reactive mode and proactive mode. Reactive mode is activated when water cut increases and oil rate or flowing bottomhole pressure (BHP) decreases, at which point the workflow performs local history matching to update the well performance model and optimize the settings of the 5 ICVs to obtain the minimum water cut and maximum oil rate at given constraints. Proactive mode occurs every month or quarter when the numerical simulation runs hundreds of scenarios to obtain the best combination of ICV settings to maximize oil recovery and minimize water injection and production.

The workflows described in this paper demonstrate the potential to manage ICV settings to substantially increase oil production while managing water influx.
Real-time Diagnostic Analysis of Artificially Lifted Wells: A Smart Workflow Approach
Authors: Agarwal Amit Kumar , Purwar Suryansh , Bravo Cesar Enrique
Published: June 2014

The value proposition of petroleum workflow automation traditionally includes the ability to provide comprehensive production surveillance to streamline efficiencies and avoid unwanted downtime. But this is just the first step in a production workflow automation strategy. The ability to analyze flow measurements and other operational data in real time to continually diagnose and optimize well performance is a major step forward. In its current setup, the proposed method can be applied to continuous gas-lift and ESP-operated oil wells. A central problem when operating gas-lift and ESP wells is to identify and address issues causing underperformance at the correct time. The purpose of this paper is to describe a method for real-time analysis of the performance of artificially lifted wells and then accelerate and improve the diagnosis and decision-making processes. The solution presented here can operate in complex, high-frequency data environments and has the ability to federate multiple data sources. The method is based on proven steady-state nodal analysis techniques and models multiphase flow from the reservoir to the wellhead. The well model is updated, and the model results are displayed as soon as new data arrive, thereby providing the users with the most current information from their well. Available data include pressure gradient curves, inflow and outflow curves, gas-lift or pump performance curves, the current model operating point, and the recommended opportunity point. The real-time measurements combined with the real-time model calculations provide an advanced tool for artificial lift system analysis and troubleshooting. This method is designed to generate actions, such as decreasing or increasing the gas injection rate, pump frequency, and choke setting. The ultimate benefit is the ability to identify performance issues and opportunities at the correct moment in time.
Real-Time Rate of Penetration Optimization Using the Shuffled Frog Leaping Algorithm (SFLA)
Authors: Yi Ping , Kumar Aniket , Samuel Robello
Published: June 2014

The increasing complexities of wellbore geometry imply an increasing well cost. It has become more important than ever to achieve an increased rate of penetration (ROP) and, thus, reduced cost per foot. To achieve maximum ROP, an optimization of drilling parameters is required as the well is drilled. While there are different optimization techniques, there is no acceptable universal mathematical model that achieves maximum ROP accurately. Usually, conventional mathematical optimization techniques fail to accurately predict optimal parameters owing to the complex nature of downhole conditions. To account for these uncertainties, evolutionary-based algorithms can be used instead of mathematical optimizations. To arrive at the optimum drilling parameters efficiently and quickly, the meta-heuristic evolutionary algorithm, called the ‘Shuffled Frog Leaping Algorithm,’ (SFLA) is used in this paper. It is a type of rising swarm-intelligence optimizer that can optimize additional objectives, such as minimizing hydromechanical specific energy.

In this paper, real-time gamma ray data are used to compute values of rock strength and bit-tooth wear. Variables used are weight on bit (WOB), bit rotation (N), and flow rate (Q). Each variable represents a frog. The value of each frog is derived based on the ROP models used individually or simultaneously through iteration. This optimizer lets each frog (WOB, N, Q) jump to the best value (ROP) automatically, thus arriving at the near optimal solution. The method is also efficient in computing optimum drilling parameters for different formations in real time. The paper presents field examples to predict and estimate the parameters and compares them to the actual real-time data.
Strategic Well Test Planning Using Random Forest
Authors: Aulia Akmal , Rahman Aulia , Quijano Velasco Juan Jose
Published: June 2014

Optimizing a huge oilfield with hundreds of wells would involve thorough analysis. Here, the performance of a subset of those wells might be a critical factor. Therefore, it is important to obtain accurate information on that subset.

Obtaining accurate information on an individual well is usually done via a proper well test analysis. Although performing a well test is relatively expensive, it can provide important information such as the skin, reservoir pressure (i.e. BHP), permeability, and nearby faults.

In this study, we would like emphasize on the measurement of BHP. This emphasis is chosen due to the fact that the BHP from a subset of all wells can be a contributing factor towards the field oil recovery factor. Hence, the objective of this study is to find that subset of wells based on uncertainty studies conducted via reservoir simulations.

Here, the uncertainty study involves performing 100 Latin Hypercube Monte Carlo (LHMC) sampling of the reservoir simulation input parameters. For each of the 100 runs, the uncertain input parameters and simulated BHP values/trends for each well are recorded. Thus, a dataset consists of the input parameters, simulated BHP for each well, and the field oil recovery factor as columns will be generated.

The random forest (RF) algorithm was implemented in order to find the subset of wells mentioned. RF algorithm is simply a collection of decision trees (DT), where the results generated by RF were obtained by using a voting mechanism among the trees involved. Several trees were sampled from the generated forest, and reveal interactions between the monitored BHP value/trend with other parameters. Combination of LHMC and RF can also be seen a global approach to sensitivity analysis, since RF can reveal the rank of importance of the RF’s independent variables based on a collection of uncertainty runs.

In the exploration and production (E&P) applications, DT has been used extensively; appraising, real option valuation selecting an artificial lift method, predicting permeabilities and detecting fracture corridors. However, to the best of the authors’ knowledge, RF had never been implemented in any E&P activities, particularly in strategic well test planning.
Standardized Reporting of Hydraulic Fracturing Treatments Supports Production Optimization and Meeting Regulatory Requirements
Authors: White Ky W. , Lamborn Raymond , Svensson Inge , Sui Xiaojing , Sanders Steven , Thorsen Arve , Parks John , Hughes Jeffrey A. , Hamilton Fiona , DeSantis Cory , Fore Keith , Slack Ronnie
Published: June 2014

Hydraulic Fracturing treatments generate large volumes of valuable data. The industry recognizes this data can be leveraged to optimize various parameters for oil and gas production from a well. Additionally, there are evolving regulatory reporting requirements that require a standardized exchange of information with the service providers and the regulatory organizations. Historically, data was provided to the well operator in custom paper or varying digital formats, resulting in delays, overhead, and inconsistent information during the database import process.

In response, the Energistics© global consortium 1 united a wide variety of industry professionals to develop the stimJob Object open exchange standard for hydraulic fracturing in November, 2010. The stimJob Object standard was subsequently updated and incorporated into version 1.4.1.1 of the WITSML™ (Wellsite Information Transfer Standard Markup Languag) standard as released in July, 2012.

The stimJob WITSML 2 report was initially deployed to the high volume USA market as a post-job report for each stage of the hydraulic fracturing operation. It is an XML file containing a data record of the treatment including rates, pressures, volumes, densities and additives. The digital data format conforms to WITSML-compliant requirements for use in several commercial applications. The stimJob report utilizes the current version of WITSML, v1.4.1.1, which is a further refinement of the data-object specifications for ease of implementation and use. WITSML is designed for the seamless flow of well data between the operators, service companies, and regulatory agencies, to speed and enhance decision making and reporting.

This paper outlines the content of the stimJob report, how the data is exchanged with the operator and the beneficial results from the early adoption of the standard into the stimulation workflow.
Digital Oilfield Implementation in Naturally Flowing Oil Fields with Increasing Water Encroachment: One Company's Experience in Burgan Field
Authors: Al Jasmi A. , Choudhuri A. , Joy D.
Published: June 2014

Kuwait Integrated Digital Field Gathering Center 1 (KwIDF-GC1) pilot project was launched in Burgan field in 2009 as an investigation into how a cross-functional and cross-domain infrastructure could be established to aid in the achievement of corporate goals set for the following two decades. The company’s vision for 2030 includes a philosophical shift in the way that the country’s workforce accomplishes its tasks, employing latest technologies and work processes. The project solution integrates field instrumentation with workflows automated in software and focused collaboration.

All well sites were instrumented with pressure and temperature gauges, multiphase water cut meters, remotely automated chokes and electronic H2S detectors. Automation of field was the first step in providing the advanced technology required of this project, realizing tangible advantages in minimizing the health, safety and environmental (HSE) exposure of field personnel. Well site data can be read, and choke positions can be set, remotely at the gathering center without the need for field personnel to enter hazardous areas. The implementation is digital throughout, employing a field-level WiMAX radio system to provide fast and secure Ethernet-based communication from gathering center to the wellhead. Work processes were converted into automated digital workflows supported by advanced network modeling and nodal analysis software in a state-of-the-art collaboration center. This paper presents framework of the pilot project demonstrating the hardware and software tools that have been used to optimize production of the Burgan field assets as a part of the KwIDF-GC1 project. The concentration of this paper will be a detailed discussion on designing of the field instrumentation system.
From Market Basket Analysis to Well-head Monitoring: Using Events to Increase Oil Recovery
Authors: Bailey R , Lu Z , Shirzadi S , Ziegel E
Published: June 2014

BP has a successful, limited scope deployment of a non-parametric capability called Event Detection and Association (EDA). The technology resembles ‘Market Basket Analysis’ tools used to carry out associative assessments of item sets. Variations from the original analytical approach have been found necessary before the EDA techniques could be used to solve real-world oil and gas problems. These changes are based on fundamental physical laws such as conservation of mass and the recognition that systems of relevance all contain time delays between the ‘items’ that are to be tested for association. EDA comprises part of a suite of tools collectively referred to as Top Down Waterflood Diagnostic and Optimisation (TDWF). TDWF is a top down reservoir simulation toolkit capable of developing a statistically valid reservoir representation based purely on operational data together with a limited set of configuration data (the x, y location of wells is required). EDA contributes an independent validation of the Capacitance Resistivity Model (CRM) using the same data further processed to extract causal events on the injectors and delayed-response events on the production wells. By studying the time based correlation of these input and output events the basic TDWF CRM model is either confirmed or has suggestions made for improving its predictive capability.

Early studies on three reservoirs, when combined with insights from suppliers of four different data-driven technologies, confirmed the robustness of EDA. A limited trial deployment followed in four operating regions. The users’ studies have generated insights and improved the product design and capabilities. EDA can deliver insights into well connectivity in the subsurface. Working from data alone EDA can even approximate the findings of a much more expensive tracer study and deliver these insights in a very short time and at a fraction of the expense.
Big Data in Exploration and Production: Silicon Snake-Oil, Magic Bullet, or Useful Tool?
Authors: Cameron David
Published: June 2014

Big data is a nebulous and much-hyped concept in IT. IT companies have noted that exploration and production involves handling and storing large, and ever-increasing, amounts of data. They are therefore positioning their various "big data" products as solutions in search of E&P problems. This paper presents an overview of big data technologies and discusses ways in which these technologies could be used to improved exploration and production operations. The paper will present a working definition of what big data is for the upstream oil and gas industry. Big data is a repackaging of a variety of IT technologies, including pattern analysis and recursive estimation using streaming data, management of large-scale parallel databases, in-memory computing, fast search, natural-language processing and the statistical analysis of large datasets. In many ways, the E&P industry has been a pioneer in these areas, where the technology push has been driven by geophysicists and engineers rather than computer scientists and statisticians. The message presented is that these tools give allow faster processing, searching and analysis of data, but the their full benefits will only be obtained when they are (a) combined with physical insight and models, (b) used by talented and experienced engineers and (c) deployed to solve real and pressing business problems and (d) integrated with corporate IT. The paper will discuss the organizational and ethical implications of big data, including issues such as: the use of big data in small organizations; the roles of IT companies and traditional service companies in implementing big data; the maintenance of security, privacy and accountability using big data and the use of big data in collaborative workflows and integrated operations.
The Future of Telemedicine in O&G
Authors: Thorvik K. , Nystad A. , Skogås J. G. , Fernandes A. , Reegård K. , Simensen J. E. , Rindahl G. , Silva E. , Bergsland T. , Klingsheim O. , Evjemo T. E.
Published: June 2014

This paper presents an ongoing work in on the future of telemedicine in O&G. There has been a huge development in the use of video consultation between remote patients and the doctors. We believe the future of telemedicine in O&G will add to this workflow by investigating how we can transfer visual medical data between "offshore nurses" and "medical experts" at hospitals onshore in order to improve diagnostics and treatment. We will describe a decision support system that supports an optimal workflow and collaboration, between medics onshore and offshore. The goal is to make better and faster medical decisions, and improve the quality of healthcare offshore.

The oil companies have much of the same structure and same challenges in remote medical treatment. We investigate an optimal workflow including how technology supports a new telemedicine work process by transmitting very high quality information (e.g. ultrasound images) to the cardiovascular medical experts.

We will review our work on developing a prototype "on the go" solution between medics offshore and the medical experts onshore at the hospital. The concept will be based on a Pad/PC solution capturing the ultrasound image transmission between the user and experts, a systematic work process and a knowledge base integrated in the Pad/PC "on the go solution". With optimal workflow it should not take more than 5-7 minutes from the starting point to have a decision from the medical expert. This will improve diagnostics, medical safety and health quality on offshore installations.