bluuebunny/crossref_metadata_2025 huggingface dataset:
The PetroChallenge – An Innovative E&P Learning Experience Using an Interactive Learning Simulation
Authors: Venugopal Kalyanaraman , Kelly Paula , Jamaluddin Abul , McConnell Charles , Alger Monty , Morgan Eugene , Ni Rui , Dunn Ronald , Grasselli Giovani
Published: September 2016

For decades, the university education has provided a base foundation and prepared students to join the workforce. Despite the technical foundation, students lack practical exposure. To bridge the practical knowledge gap, the industry has launched various short duration interns/externs programs. Even then these programs are not broad enough to provide a holistic understanding of the Oil and Gas Industry. Therefore, in 2015 to address this practical application NExT, a Schlumberger company, launched an interactive simulation based learning competition called PetroChallenge sponsored by Oil and Gas companies. The students are grouped into integrated teams of 3 or 4 participants; for example, an engineer, geoscientist and a business major student forms a team. Each team then acts as an operating company being fully exposed to the complete upstream cycle of the oil and gas industry using a web-based simulator called OilSim. Throughout the event, these teams make Exploration and Production (E&P) decisions and their actions and choices are then judged through the Net Present Value (NPV) of their company. The winning teams are declared based on the combined highest NPV and credibility points, earned by each team based on their challenge decisions and corporate social activities and engagements.

As E&P companies are making a stride to reduce the "Time to Autonomy" for new recruits, an event like the PetroChallenge can be a good enabler for students to be better prepared when joining the workforce. In these unique events, the sponsoring companies have an opportunity to evaluate potential recruits in action, not only from a technical perspective, but also, their business acumen including negotiation, risk taking and decision making skills. In the same token, students get an opportunity to network with their potential employers.

In 2015, three Universities (Rice, Penn State and University of Toronto) and ShawCor partnered with NExT and launched the inaugural PetroChallenge. These three events marked a phenomenal impact in students' learning and understanding of the oil and gas decision making process. Two winning teams from each of these events met at the North America finals, with Penn State becoming the first North American PetroChallenge university champions.

This presentation is prepared to share the key learnings and benefits of this type of student engagement prior to them moving into the real world.
Enabling Expected Value Economics Thinking within a Capital Budget Constrained E&P Portfolio
Authors: Adejumo Adebola , de Jesus Justin , Casey-Yorro Meaghan
Published: September 2016

One of the most important investment decisions that exploration and production (E&P) organizations make is allocating limited capital amongst the myriad projects in the corporate portfolio. The importance of making more effective capital allocation has become more apparent with the prevailing depressed oil price environment. This paper enumerates the methods used in deciding which projects to fund and puts them in the context of prevailing market conditions. It then identifies shortcomings in the most common methods used and suggests an optimal alternative.

In the prevailing depressed market conditions, most E&P organizations face significant capital spend cuts. More often than not, capital is allocated to projects based on a net present value (NPV) optimized portfolio. This sometimes results in the unintended consequence of sanctioning relatively capital inefficient projects that return less value per capital spend. A case study of a hypothetical portfolio of 12 projects including exploration, development, and production assets is used here to demonstrate this issue. Three methods—a rank and cut, NPV-optimized, and discounted profitability index (DPI) optimized—were used to determine projects to fund.

Results and insights from this analysis show that optimizing a portfolio based on NPV to allocate capital results in the unintended consequence of funding lower DPI projects, especially in an era of deep capital spend cuts, when prudence and corporate survival take precedence over production and reserves replacement targets. This paper highlights the value of expected value thinking in decision making and concludes that a DPI-optimized portfolio for capital allocation ensures E&P organizations obtain better value for capital spend and helps identify divestiture candidates when the need to raise capital ensues.

This paper leverages the effective use of cloud-enabled integrated solutions to evaluate prospects in a timely manner with minimal information and fewer resources, delivering results in a matter of minutes that would hitherto have taken a team of professionals several months to achieve.
Advanced Distributed Fiber Optic Sensors to Monitor Cement Hydration and Detect Annular Hydrocarbon Migration for Enhanced Zonal Isolation
Authors: Wu Qian , Nair Sriramya , Shuck Michelle , van Oort Eric , Guzik Artur , Kishida Kinzo
Published: September 2016

This paper presents an advanced fiber optic distributed temperature and strain sensing (DTSS) system designed for real-time in-situ monitoring of cement annuli in an oil and gas well. The DTSS system used in this study of cement quality and zonal isolation uses both Brillouin and Rayleigh backscattering phenomena, allowing one to separate strain and temperature using a single optical fiber.

The first part of the paper focuses on monitoring the exothermic cement hydration process after a cement slurry is displaced into an annular space. In the laboratory, temperature and strain profiles were measured independently using the DTSS system and thermocouples at various temperatures to quantify the effect of heat release during cement hydration. These independent temperature measurements showed excellent agreement. Contamination of cement due to incomplete displacement of drilling muds by cement slurry was also simulated in the experiments. Contamination was found to decrease the amount of heat generated during the cement hydration process. The degree of cement hydration and the presence of cement in the annular space – or lack thereof - could thereby be quantified. It is shown that the temperature profiles measured using the hybrid-DTSS system can be used to detect both the top of cement (TOC) as well as annular sections that are either left uncemented or contaminated with drilling fluid. This is highly relevant information, because contamination of cement is one of the main factors that negatively affects zonal isolation directly by creating paths for hydrocarbon migration or indirectly by weakening the cement, making it susceptible to damage from cyclical pressure/temperature loads.

In addition to monitoring cement hydration, specially designed fiber optic sensing cables were used to detect the presence and migration of hydrocarbons in cemented annuli, either because the cement was absent or compromised by cracking/fracturing. The presence of hydrocarbons in cemented annuli could be detected even after the cables were exposed to well construction fluids such as synthetic-based drilling mud and spacer fluid. Moreover, the materials used were sensitive to the type of hydrocarbon, allowing indirect hydrocarbon fingerprinting and determination of the origin of the hydrocarbons behind pipe. This presents a powerful new tool to assess the quality of zonal isolation behind casing, with the ability to monitor in real-time over the entire lifecycle of the well. In this capacity, it may provide guidance on such important decisions as the need for well intervention and remedial cementing.
Application of Simultaneous Operations in Saudi Arabia's Causeway Oilfields Development
Authors: Arukhe James O. , Duthie Laurie S. , Hernandez Jose Rodulfo , Ahmari Abdulrahman S , Hanbzazah Shadi M
Published: September 2016

Crude oil delivery expectations under timeline constraints sometimes necessitate simultaneous operations (SIMOPS) for completing field development requirements. During one such SIMOPS exercise on Field X, a major sour oilfield in causeway sites close to the Arabian Gulf in Saudi Arabia, different sub-organizations coordinated potentially different, yet complimentary operations or activities in the same location together. Challenges from the exercise included instituting an interface criteria for promoting safe operations and good technical standards for all parties. After considering work requirements, a SIMOPS team facilitated an assessment review, devised a response framework with rescue, evacuation, or emergency response plans in the event of accidental release of H2S, besides making certain other modifications to satisfy multiple stakeholders. An auditable matrix was instituted for regulating and supporting permissible simultaneous rigless and construction activities while upholding health, safety, and the environment.

The scope of this paper is to show how SIMOPS was successfully planned, executed, and managed for the first time in causeway drill sites in Saudi Aramco to prevent safety and environment incidents while ensuring to meet well tie-ins and field production targets.

The approach involved delineating clear reporting lines or control hierarchy for various stages of operation, avoiding schedule clashes by outlining clear scenarios for each organization. Guidelines were binding for all team members because of collaboration among multidisciplinary team members to develop suitable hazards identification and risk management plans thus formulating the foundations for the SIMOPS and ensuring safety of workers.

SIMOPS facilitated the unlocking of the giant field's potential while optimizing potentially conflicting but complimentary activities on the same drill site to meet crude demand reliably and safely. Success with SIMOPS has allowed oil production delivery from the field and safe working environment for crews.
A Critical Examination of the Way the Drilling Industry Traditionally Calculates Pressure Drop for Fluids in Laminar Flow
Authors: Hemphill Terry
Published: September 2016

Recent advances in the calculation of circulating pressure drop produced by drillpipe rotation have led to questions regarding the way the drilling industry traditionally calculates pressure drop in a circulating annulus. Because few publications discuss the hydraulics of rotation of an inner pipe in an annulus where the outer wall is stationary, there is still not a large volume of work on the subject. This paper reviews the published literature on fluids in laminar flow and discusses what is missing from the equations and the way forward.

Common equations in the literature use multiple factors to calculate pressure drop in annuli without including the effects of drillpipe rotation. The most frequently used equations include shear rate at the wall (various methods), shear stress at the wall, numerous coefficients used as patches to power-law (PL) and Bingham plastic (BP) hydraulic models, shear rate and hole geometry correction factors, drillpipe roughness factors, and drillpipe eccentricity (ε). All of the equations are missing a general, straightforward method for calculating pressure drop, both with and without rotation of an inner pipe.

Because the current API Recommended Practice 13D "Rheology and Hydraulics of Oil-well Fluids" (2010) recommends the Herschel-Bulkley (HB) rheological model for hydraulics calculations, special mention is made in this paper regarding use of the pertinent equations employing the HB model. In short, there should be a fairly straightforward method for calculating laminar flow pressure drop for axial flow with no drillpipe rotation and for helical flow that is produced by drillpipe rotation in a circulating annulus.

The proposed method for calculation of fluids in laminar flow includes: A grid across the narrowest annular gap as defined by the input drillpipe eccentricity (ε).A single velocity equation that predicts point velocities across the annular gap.Average shear rates calculated for each pair of predicted velocities in adjacent cells.Average local shear stresses calculated for each average annular shear rate.Cumulative shear stresses necessary to move the entire annular cross-sectional area.Pressure drops calculated from the cumulative shear stresses.

With this fairly straightforward method, hydraulic calculations are simplified because special coefficients or correction factors are not used. Drilling engineers should find that the outlined methods help to clarify traditional pressure drop calculations for fluids in laminar flow.
New-Generation Ultrasonic Measurements for Quantitative Cement Evaluation in Heavy Muds and Thick-Wall Casings
Authors: Thierry S. , Klieber C. , Lemarenko M. , Le Calvez J.-L. , Brill T. M. , Barrou T. , Hayman A. , Mege F. , Van Os R.
Published: September 2016

In this paper, we describe major improvements to ultrasonic logging techniques used for cement evaluation. Specifically, we explain engineering solutions developed to tackle known limitations such as logging in heavy (ultrasonically attenuative) muds, and very large and very thick pipes.

On the hardware side, new heavy mud/thick casing transducers are presented together with dedicated large-diameter logging heads for both pulse-echo and pitch-catch (flexural attenuation) techniques. On the processing side, we present a novel pulse-echo inversion scheme, based on real time inversion using accurate 3D models for metrology accuracy and a new scheme that does not require a priori knowledge of mud properties (specifically its acoustic impedance, Zmud). Through this, Zmud becomes an output parameter of this novel processing and we present field examples of such logs where we now image features such as mud deposition and segregation in deviated pipes. This new processing enables easier and more accurate interpretation of the cement sheath together with critical information on the logging fluid. The validity of the measurement across the operating range is demonstrated in this paper through results from both high precision laboratory measurements and several logs acquired during the last few years' field test campaign. Together with the fundamental sensor and processing improvements, we present engineering changes to the logging platform, enabling up to three times faster logging and accurate well site logs delivered right after rig down. Finally, we demonstrate that the combination of the pulse-echo and pitch-catch techniques, with its high azimuthal resolution, can probe the annulus up to the cement/formation or cement/second casing interface, making it a powerful technique for cement evaluation.

Previous limitations (such as mud weight, casing size and thickness) have been overcome and this has been fully demonstrated in both the laboratory and the field. Thus ultrasonic cement evaluation techniques now enable accurate and critical decisions to be made–from well construction to plugging and abandonment–in all conditions, casing sizes, and mud and cement types.
A New Method to Estimate Cementation and Saturation Exponents From Dielectric Dispersion Data
Authors: Venkataramanan L. , Donadille J. M. , Reeder S. L. , Van Steene M. , Gkortsas V.-M. , Fellah K. , Ramsdell D. , Al-Rubaiyea J. A. , Al-Ajmi F. A. , Al-Houli M. , Wilkinson P. , Bajunaid H.
Published: September 2016

Petrophysical models are applied to wireline dielectric dispersion measurement to estimate water saturation, water salinity, and the water phase tortuosity mn. The parameter mn (which is also referred to as "MN" in other sources) combines the effects of pore-space tortuosity (cementation exponent m in Archie's equation) and distribution of water and hydrocarbons in the pore system (saturation exponent n). We present a new method to separate these effects and obtain Archie's m and n exponents from this water phase tortuosity mn. The method described in this paper makes it possible to fully utilize dielectric dispersion log data to estimate key petrophysical parameters in situ, whereas these parameters were previously only available through expensive and time-consuming core analysis. Together, m and n may be used to infer wettability and estimate water saturation more accurately and reliably in the uninvaded zone.

When m can be estimated by nuclear magnetic resonance (NMR), borehole images, or core resistivity measurements, the dielectric parameter mn can be used to estimate n, which can be used to infer wettability. In the absence of capillary pressure hysteresis, mn obtained in the invaded zone by downhole dielectric tools may be used to estimate water saturation in the uninvaded zone by using deep resistivity tools and Archie's law. Practically, these applications are very limited in their scope. The new method assumes that the parameters m and n from the Archie equation are constant for depths with similar rock types. For each rock type, the parameter mn is plotted against a variable combining porosity and water saturation. The data are then fit with a linear function that yields Archie's m and n when the variable takes the values of 1 and 0, respectively. The fit is more heavily weighted towards data points with lower uncertainty.

We demonstrate via simulations that Archie's m and n exponents can be accurately and reliably estimated by the new method. This is supported by our study of several limestone cores in various stages of brine/oil saturation in the laboratory where we find that the predicted linear model fits the data reasonably well and can be used to estimate both m and n. We have also applied this method to several wells of a carbonate field. Rock types in each well are determined based on factor analysis of NMR data. The dielectric data for each rock type across all the wells are then analyzed with the method described here to yield values of m and n for each rock type, together with an evaluation of the uncertainty on these parameters. The results are then compared with m and n data from special core analysis (available in two wells of the field). We find that the new method's results fall within the uncertainty of the core analysis results.
Multiphase Analytics in a High Water-Cut Environment
Authors: Gannaway Gregory R. , Ibrahim Mazher , Pieprzica Chester
Published: September 2016

Historically, Rate Transient Analysis (RTA) has been performed to characterize the reservoir properties associated with multi-fractured horizontal wells (MFHW), using single-phase linear flow models (Clarkson et al., [2014]). This paper purposes a different look at RTA, by applying traditional diagnostics to more than one producing fluid phase. These RTA techniques can yield substantial insight into reservoir characteristics and performance, and simultaneously help one understand the true reservoir being accessed by the wellbore. By incorporating multiphase RTA techniques, the strategic development of some high water producing unconventional targets can be optimized through section spacing design and reduced offset fracture communication.

The premise behind this paper is centered on the extremely high water cut seen in wells within the Wolfcamp and Bone Spring formations, located in West Texas's Delaware Basin. As a wells produced fluid gains substantial proportions of water, traditional single phase analytic techniques need adjustment to allow for accurate fluid flow modeling and reservoir characterization.

This paper evaluates an 8 well case study of actively producing wells in the lower 3rd Bone Spring formation. This case study provides insight into the RTA workflow for multiphase analytics, evaluating the oil and water fluid constituents, both independently and together. This approach yields more accurate characteristics of producing reservoir geometry, completion properties, stimulated formation permeability and inter-well fracture communication.
Successful Use of Sophisticated Flow Modelling in the Planning and Operational Phase of Drilling, Liner Running and Cementing Operations: All in Managed Pressure Mode
Authors: Barr Aas I. , Skjerve K. , Haaland L. E. , Svendsen M. , Rommetveit R.
Published: September 2016

The managed pressure drilling (MPD) technique was chosen to drill a well on the Gullfaks A platform as a risk mitigating factor. In addition, the MPD technique gives accurate flow measurement, provides the potential to handle pressure variations quickly, and determines the drilling window. This paper presents the successful implementation of a sophisticated hydraulic model during planning and execution of a MPD operation in Gullfaks Well A-10B.

MPD service was delivered by a major service company with equipment coupled to a third-party real-time advanced transient hydraulic model. This model was used to calculate upstream choke pressure during MPD. It was also used in the planning stage to ensure operation was feasible within the pressure window with the selected fluids and drilling parameters. The system was run in automatic mode. Initially, only one section was planned for drilling in MPD mode. However, because of the losses observed and bottomhole pressure (BHP) flexibility provided by the MPD system, it was decided to drill the next section in addition to running and cementing the liner.

When the well was completed, three sections were drilled and two liners were run and cemented using MPD. The use of an automatic MPD system with a sophisticated hydraulic model helped ensure the well delivery was achieved according to plan without any major issues. The losses that occurred were detected and reduced significantly only by reducing the bottomhole target pressure. Dynamic drawdown tests in addition to a dynamic formation integrity test (FIT) confirmed the drilling window before drilling the second section. During the planning of cement job, a close working relationship between all parties was established in order to find the best possible solution for the well and achieve a delivery of a successful well. The planning tool used is a sophisticated hydraulic model that calculates a constant dynamic well pressure during the simulation of the cement job. The simulations were verified during the cementing job, with a good cement job as the result. Both liners were run and cemented with full returns and rotation.

This paper presents the challenges involved during this well project, how these challenges were handled by thorough planning, and finally the operational phase itself with focus on the MPD system, including the advanced flow model.
Visual Data Analytics: Morphological Image Processing Approach on the Evaluation of Foamed Cement Quality
Authors: Ding Bingjie , Samuel Robello
Published: September 2016

Foamed cement is widely used during cementing operations in which lightweight slurries are necessary. Foamed cement helps prevent gas migration and is often used in high-stress environments. A stable foamed cement has a uniform distribution of distinct bubbles, which helps ensure the gas will not break out of slurry. An unstable cement can result in gas coalescence with uncemented sections caused by channeling in the well and density inhomogeneity. Evaluation of foamed cement is necessary before use.

This paper proposes a methodology for evaluation of foamed cement quality using two-dimensional (2D) images and an efficient k-means clustering algorithm under image processing. A combination of image-processing techniques is applied to segment bubbles in foamed cement computed tomography (CT) scans. These scans include image compression, morphological image processing (MIP), and image segmentation. Based on the image-processing results, a computer program is developed for foamed cement qualification using a k-means clustering algorithm. The algorithm uses evaluation values calculated from the foamed cement qualification equation, which provides a critical point and separates the data into two clusters. When an image is inserted, the program calculates the evaluation value automatically and assesses its qualification.
Development of a Subsurface Reverse Circulation Tool System to Cement Weak and Depleted Zones in Deepwater Formations
Authors: Reagins Deandre , Herr David , Jee Bobby , Ownby John , Duthie Jason , Giroux Richard , Kendziora Larry
Published: September 2016

Reverse circulation cementing is a placement technique that reduces bottomhole equivalent circulating densities (ECDs) and reduces lost circulation risk in wells in which conventional circulation pressures would break down formations. Until now, reverse circulation cementing has been performed only on land or in shallow-water wells in which the annulus was accessible from the surface to pump down. This paper describes the design, development, and validation of technology that enables subsurface reverse circulation.

Gaps in technology have made it challenging to transfer reverse-cementing-placement techniques to primary cementing operations in deepwater. To reverse cement a liner, fluids must be pumped down the work string to prevent potential contact inside the riser and blowout preventer (BOP), and then fluids must be injected into the annulus downhole while full circulation continues. A tool system was developed to facilitate this unique flow path, provide alternative methods to set liner hangers, and provide flexibility for contingencies and other operational requirements.

The developed subsurface reverse circulation tool system uses radio frequency identification (RFID) technology so that the tools can be operated remotely and repeatedly either by RFID tags or through surface-pressure pulse sequences. Three RFID-activated tools were designed: a circulation tool, a crossover tool, and a downhole flapper. The prototype tool system was first evaluated through bench testing of individual components and then through large-scale rig testing. During the rig trials, the entire system was run into a test well, and a multiday sequence of flow testing validated the function and performance of each tool. After successful testing in rig trials, the subsurface reverse circulation tools (RCT) were deployed in the Appalachia basin field, located in the Northeastern United States.

This paper discusses the requirements of a subsurface reverse-circulation-cementing system. It describes the design, development, and validation of technology that enables subsurface reverse circulation. It also describes the prototype system that was built and the field testing results. This new capability enables the cement to be pumped down the work string and then to exit to the annulus at a point above the liner string.
Making a Cross-Flow water injector in the Alvheim Field
Authors: Langaas K. , Hjellbakk A. , Leonthin M. A. , Stuart K. L.
Published: September 2016

A dual lateral horizontal well was drilled on the Kneler structure of the Alvheim Field (offshore Norway) in 2015. The use of a newly processed 4D seismic dataset changed the original planned target for the main branch and led to justifying drilling the branch below an existing producer. The objective of the main branch was to target undrained oil below a stratigraphically compartmentalized segment. The Alvheim Field started production in 2008. The baseline seismic survey was acquired in 1996 and a 4D monitor survey was acquired in 2013. The 4D seismic data was used to estimate the movement of the oil water contact, and 4D difference geobodies were benchmarked against production data directly, giving high confidence in the estimates. The 4D difference geobodies were integrated in the history matching process. A lower zone infill target below an existing upper zone producer was identified as the result of the multidisciplinary data integration. The lower zone has excellent pressure support via the large Heimdal aquifer system while the upper zone producer has limited pressure support and has historically produced at low rates. Pre-drill reservoir simulation studies indicated a benefit in enabling cross-flow between the two zones. The drilling results showed oil as predicted by the 4D seismic data. However, the upper zone was thicker than expected. A thin oil column was found in the lower zone before drilling into water, again confirming the 4D seismic interpretation. As the lower zone target was smaller than expected, the main value of the branch was refocused towards enabling optimal cross-flow. The pre-drill reservoir models were updated pragmatically and studies were done to optimize the lower completion, e.g. deciding the optimal cross-flow rate, production and injection intervals and how to use inflow control devices to assist the clean-up of all zones. The clean-up went as planned in November 2015 and a 20 bar drawdown was achieved across the injection interval of the branch. The branch was produced for 40 days before shut-in to act as a cross-flow injector. Pressure interference data indicated a successful clean-up of the injection interval. The cross flow well has showed to work as intended giving an increased oil rate of around 4000 stb/d. A cross-flow injector can be a cost effective solution for partly segmented compartments close to strong aquifers. To the knowledge of the authors, no example of this type of cross-flow injection has been documented in the literature.
Deconvolution of Vibrational Data to Reduce the Ambiguity in Downhole Tool Failure
Authors: Lakhanpal Vikrant , Samuel Robello
Published: September 2016

As the drilling industry enters the era of big data, it has become necessary to find ways to organize and understand the vast amounts of real-time high frequency data recorded.

Shor et al. (2014) show that real-time accelerations recorded down hole actually differ from those predicted by various models, either in the high frequency range or at peak values. These differences in vibration levels can be attributed to noise from various sources, such as the motor or surface equipment, design of measurement devices, uneven shape of the borehole, and/or dynamic effects, such as dampening/cushioning of fluids, bit rock interactions, drillstring-borehole wall interactions, etc. These differences can cause real-time drill log analysts to miss instances of actual failure or predict false failures.

The industry currently focuses on the peak and average values of the accelerations recorded down hole, and there is no established method to examine the trend of these accelerations. The methodology proposed in this paper first focuses on obtaining the actual unmodulated acceleration values from the recorded downhole gauge data and then processes these values to understand the trend of acceleration as the drilling proceeds. This demodulation (or deconvolution) of the recorded data can reduce the likliehood of false predictions and, at the same time, increase the credibility of the mode of acceleration predicted (and hence more accurately predict failure), which currently relies only on the experience of the engineer. Thus, this technique can make real-time data monitoring more reliable and simple. Further, if combined with a gamma ray log to know the lithology of the formation being drilled, this data monitoring technique can reveal a significant amount of information.

In addition, this paper suggests calculating instantaneous jerk intensity and decomposing it to its monotonic intrinsic mode function. This reveals that these monotonic functions follow a certain trend, which might be useful in future endeavors to understand the underlying physics of drillstring failure.
Evaluating the Development of a Multi Stacked Gas-Condensate Field to Supply LNG Using A Multi-Tiered Optimization Tool
Authors: Lemke Alexander van , Bouts Marcel , Drohm Julius
Published: September 2016

For the screening of a significant new LNG development a multi-tiered optimization tool was built with the following objectives: To optimise the sequence of drilling and producing condensate and gas from a field consisting of multiple stacked reservoirs.To understand that gas requirements could be fulfilled to supply gas to the multiple planned LNG trainsTo evaluate if the tool delivered export results of various scenarios for economic screening and future auditing

An integrated model was built consisting of a Controlling Optimization Software (Resolve) to communicate and control the link between a Surface Network Development (GAP), the wells (Prosper), material balance model (MBAL) and a data export and plotting software (Excel). Visual workflow programming in Resolve allowed for simple adjustment of constraints and inputs through all the linked models which can optimise of multiple scenarios.

Parameters that were optimised included: Sequence of reservoirs to produceWell phasing over the different reservoirs showing varying condensate gas ratiosWell type, count and respective targeted reservoirSurface infrastructure including pipelinesCompressor timing

The fully integrated model provided the required flexibility for evaluating various scenarios while delivering credible consistent results. Running quick scenarios can help to make decisions for the planning of the surface network and production thus helping to reduce CAPEX. Using central controlling software simplified varying both subsurface and surface constraints for the LNG development. This included seasonality influenced safety margins, the addition of compression as soon as the gas rate potential drops below critical levels and drilling new wells into the optimal reservoir when required to fill the LNG trains.
Integrated History Matching on Interference Well Test Data in a Naturally Fractured Reservoir with Automated Adjoint Gradient Based Inversion Technique
Authors: Sarac S. , Morton K. L. , Theuveny B.
Published: September 2016

It is common practice to perform well test interpretations as stand-alone analyses with dedicated well test interpretation software, independent from the actual geologic and geophysical information used for reservoir simulation. This can lead to non-geologic interpretations, lacking in geological and geophysical prior information, which also means that the well test data cannot be readily incorporated into reservoir simulation models. This paper describes an automated history matching procedure for well test interpretation, constrained by simultaneous dynamic well test data from multiple wells, which improves production forecasting and reservoir development decisions. The procedure is applied to a synthetic naturally fractured reservoir to identify inter-well connectivity, fracture and formation properties within the reservoir volume investigated by the interference well test. The outcome of this integrated interpretation methodology with an interference test is compared to conventional interpretation results from four individual well tests in the same reservoir model.

The permeability field of the reservoir model was automatically updated using an adjoint gradient-based inversion technique to produce a pressure response that matches the well test data. The updated permeability field was then used to generate a fracture network in the model. The results indicate that the conventional interpretation of individual well tests in such complex reservoirs can lead to unrealistic reservoir descriptions. On the other hand, the integrated methodology explained in this paper, together with a proper well test strategy, leads to a more accurate reservoir characterization with an updated reservoir model. The resulting fracture network that is determined from the data very well represents the original "truth" model and is able to reproduce the individual well test responses accurately. The results also show that the connectivity of the wells positioned perpendicular to the mean fracture strike orientation can also be estimated and this connectivity can be determined with an interference test and an integrated interpretation methodology.
Applying Big Data Analytics to Detect, Diagnose, and Prevent Impending Failures in Electric Submersible Pumps
Authors: Gupta Supriya , Saputelli Luigi , Nikolaou Michael
Published: September 2016

More than 90% of producing oil wells require some form of artificial lift for pumping production fluids to the surface (Bates, Cosad et al. 2004). The electrical submersible pump (ESP) is widely used and is currently the fastest growing form of artificial-lift pumping technology. About 15 to 20 percent of almost one million wells worldwide produce oil with the help of ESPs (Breit and Ferrier 2008). ESPs are usually considered more efficient and reliable among all oilfield lift systems and enable recovery of hydrocarbon fluids from greater depths at higher temperatures while handling a range of viscosities, gas-liquid ratios, and solids production. Over the years, the most common concern of operators using ESPs in their assets has been high workover costs and inadequately low system run life (Vandevier 2010). It is often observed that ESP performance declines gradually and reaches the point of service interruption due to a number of factors such as high gas volumes, high temperature, and corrosive environments. Should an ESP fail, the financial impact would be substantial, in terms of both lost production and replacement or intervention costs. Given the high cost of an ESP failure, operators are increasingly investing in real-time surveillance sytems to monitor ESP performance using downhole measurements and raise alarms in case of abnormal events such as trippings or failures. However, such systems are reactive in nature, i.e. action is taken after an event occurs. Consequently, there is a need and an opportunity to utilize the large amount of data being collected in real time from ESP operations, and to create solutions that advance from a reactive to a more proactive approach that would ideally detect issues well in advance, diagnose causes, and suggest corrective action. This paper offers such an approach. Specifically, a data-driven analytical solution is proposed to proactively monitor and transform vital statistics related to ESP performance into actionable information using multivariate statistical techniques for dimensionality reduction and pattern recognition. This real-time framework combines engineering principles with mathematical models to detect impending problems long before they occur, diagnose potential causes, and prescribe preventive action. This can safeguard ESP operations and increase uptime, extend ESP life expectancy, reduce intervention costs, and optimize production.
Integrated Dynamic Simulation Leads to Successful Start-Up of Inactive Wells Through Rigless Operations
Authors: Yusuf Rahel , Kumar Thakur Kapil , Ahmed Jama Ali
Published: September 2016

During a well start-up, fluid distribution within the well changes from a segregated phase (gas-oil-water) column to a flowing three phase mixture. For this transition to be successful, the well has to overcome the additional hydrostatic head associated with the phase segregation. Depending on the well trajectory, flowline pressure, reservoir pressure and watercut, the start-up process can be challenging for some wells as an improper bean-up procedure can result in a situation where the pressure driving force across the well is not able to overcome the hydrostatic head imposed by the liquid column. This can result in a failed start-up and, for such wells, a correct bean-up strategy is important to ensure successful start-up.

In this study, an integrated dynamic multiphase simulator is used to investigate the flow and pressure transients during the start-up of an inactive horizontal oil well which encountered start-up problems after a well intervention job to shut-off high watercut zones.

Sensitivities using dynamic simulations for different start-up procedures showed that the well could be successfully started-up by opening the well at the maximum available beansize and ensuring stable flow thereafter by keeping the bean-back above a threshold beansize. The successful well start-up procedure developed using dynamic simulations was applied in the field and resulted in additional oil production. This study demonstrates the significance of dynamic simulations in optimizing well start-up procedures. In this case, this resulted in major incremental revenue for the operator with more than 1000 BOPD added to overall production. Further, the successful start-up procedure devised using a transient multiphase simulator resorted only to well fluids routing and choke manipulation without the need for expensive rig operations and CAPEX/OPEX expenditure.
Reservoir Fluid Geodynamics; The Link Between Petroleum Systems and Production Concerns Relating to Fluids and Tar Distributions in Reservoirs
Authors: Mullins Oliver C. , Primio Rolando Di , Zuo Julian Y. , Uchytil Steve , Mishra Vinay K. , Dumont Hadrien , Pfeiffer Thomas , Achourov Vladislav V. , Pomerantz Andrew E. , Forsythe Jerimiah , Betancourt Soraya S. , Elshahawi Hani
Published: September 2016

Petroleum system modeling provides the timing, type and volume of fluids entering a reservoir, among other things. However, there has been little modeling of the fluid processes that take place within the reservoir in geologic time, yet these processes have a dramatic impact on production. Modeling and understanding of the reservoir then reinitiates with simulation of production for optimization purposes. The new discipline "reservoir fluid geodynamics" (RFG) establishes the link between the petroleum system context or modeling and present day reservoir realizations. This new discipline has been enabled by scientific developments of the new asphaltene equation of state and by the technology of downhole fluid analysis (DFA). Gas-liquid equilibria are treated with the traditional cubic EoS. Crude oil fluid- asphaltene equilibria are treated with the Flory-Huggins-Zuo equation of state with its reliance on the Yen-Mullins model of asphaltenes. Thermodynamic treatment is essential in order to identify the extent of equilibrium in oil columns, thereby identifying fluid dynamics in geologic time. DFA is shown to be very effective for establishing asphaltene gradients vertically and laterally in reservoir fluids with great accuracy. In turn, this data tightly constrains the thermodynamic analyses. These methods have been applied to a large number of reservoir case studies over a period of ten years. For example, case studies are shown that indicate baffling and lower production for parts of the reservoir that have slower rates of fluid equilibration. In addition, the newly revealed lateral sweep in trap filling is established via RFG case studies. Underlying systematics, especially for gas charge into oil reservoirs, have been revealed for a large number of fluid and tar distributions that enable a unifying and simplified treatment for seemingly intractable complexities. A case study is presented that shows three very different reservoir realizations in adjacent fault blocks for the same petroleum system model, where RFG explains all these differences. This enables key reservoir properties to be projected away from wellbore in ways not previously possible. Finally, universal work flows are shown which enable broad application of these methods through all phases of reservoir exploration and production.
A Universal Model of Water Flow Through Nanopores in Unconventional Reservoirs: Relationships Between Slip, Wettability and Viscosity
Authors: Wu Keliu , Chen Zhangxin , Xu Jinze , Hu Yuan , Li Jing , Dong Xiaohu , Liu Yuxuan , Chen Mingjun
Published: September 2016

Understanding and controlling flow of the water confined in nanopores has tremendous implications in theoretical studies and industrial applications. Here we propose a universal model for the confined water flow based on a conception of effective slip, which is linear sum of true slip, only depending on wettability, and apparent slip, caused by the spatial variation of the confined water viscosity as a function of wettability as well as nanopores dimension. Results by the model show that the flow capacity of the confined water is 10−1~107 times of those calculated by no slip Hagen-Poiseuille equation for nanopores with various wettability, in agreement with 47 different cases from the literature. This work may shed light on the controversy over the increase or decrease in flow capacity from the MD simulations and experiments, and guide to tailor the nanopores structure for modulating the confined water flow in many engineering fields, including nanomedicine, water purification, energy storage as well as the flowback of fracture fluid in petroleum industry.
Evaluation of Preformed Particle Gels Penetration into Matrix for a Conformance Control Treatment in Partially Open Conduits
Authors: Imqam Abdulmohsin , Aldalfag Ahmed , Wang Yanling , Bai Baojun
Published: September 2016

Preformed particle gels (PPGs) serve as a conformance control agent and have been used widely to control excess water production through conduits, fractures or fracture-like features. This paper ranks the parameters that impact PPG resistance to water flow in partially opened conduits and provides methods to minimize PPG penetration effect on matrices. Experiments were conducted to examine the effect of brine concentration, PPG injection pressure, back pressure, and matrix permeability on PPG resistance to water flow through conduits and PPG penetration to matrix. PPGs were swelled in different concentration brines and were injected into the conduits at a few designed injection pressures. Results show PPG resistance to water flow may have been the result of gel particle accumulation into conduits or gel filter cake formation in rock matrix or both. Their resistance increased when they were injected at high pressure. In contrast to PPGs placement through fully opened conduits, PPGs were not produced from the partially opened conduits; however, PPGs formed a filter cake on the surface of the matrix. Gel particles penetration into the matrix were only a few millimeters deep, and their penetration into to the matrix depended on matrix permeability, gel strength, and injection pressure drop across the core.