bluuebunny/crossref_metadata_2025 huggingface dataset:
Enabling Our Enabling Technologies: What will it take, and what is at Stake?
Authors: Mody Rustom
Published: June 2014

In September 2006, BP and Baker Oil Tools celebrated the installation of the world's first successful expandable monobore liner extension, an achievement that marked a major milestone for solid expandable tubular technology. A month earlier, Baker and Petrobras marked another collaborative milestone for flawless operation of an all-electric intelligent completion system in a deepwater field.

Expandable metal technology and intelligent completions are among current favorite topics of trade journal editors, conference program committees and industry analysts, because each has the potential to substantially increase well value. Yet, how will these technologies be used in five years: routinely throughout the industry, or only for niche applications? Both have been commercially available for at least 10 years, yet acceptance has been slow, despite industry pressure for their development. Although applications are expanding, each technology is currently applied in a very small percentage of wells drilled.

Why is technology uptake in the oil and gas industry slower than in other industries? How and why do we remain risk-averse? What role does "technology backbone" play? Why is operator-service company collaboration important, and how can we achieve it? And, what is at stake if we do not change?
Pore Space Characterisation and Permeability Prediction Using Fast Network Extraction and Pore Throat Conductance Calculation
Authors: Schena G. , Favretto S. , Piller M. , Radaelli F. , Rossi E.
Published: June 2014

State of the art X-ray micro-computed tomography (micro-CT) of reservoir rock samples and cuttings allows reconstruction of the pore network with a micrometric spatial resolution that is suitable for petrophysical and fluid flow property evaluation.

Synchrotron beamlines dedicated to tomography, compared to conventional micro-CT systems, allow better 3D representation of the pore space that helps segmentation of the digital-rock volume used for medial axis extraction and for pore space morphological characterization (i.e. connectivity, pore-body/throat size, shape factors, tortuosity of the throats etc.).

The pore-space medial axis is generally derived by computed intensive digital-thinning operations for skeletonization. The alternative method we describe in this work allows the extraction of the 3D centered and ‘shortest’ paths to follow in order to go through the pore space from any given point to another, using simple and well-established mathematical methods. Even if we do not consider explicitly fluid flow, one path can be viewed as the fastest streamline for laminar flow through the pore space from an intrusion point to an exiting point of the digital sample.

The method is computationally efficient and it is also amenable to parallelization.

The conductance of the irregular cross-sections of the throats is calculated with a finite element method (f.e.m.) that assumes fully developed laminar flow in the axial direction.

The network associated with the pore space is solved as a linear system and the absolute permeability of the sample is derived.

This paper reports the results of applications to real oil reservoir sandstone samples and shows the potential of the method to predict petrophysical properties from rock material not suitable for conventional analyses (i.e. drilling cuttings or crushed side wall cores).
HTHP In-Situ Mechanical Test Rig and Test Method for High-Temperature Polymers and Composites
Authors: Yuan Yusheng , Goodson Jim
Published: June 2014

High-temperature polymers and their composites have been used extensively in critical industrial applications, including composite drill pipes, tubing and casing, logging tools, and various drillable tools for oilfield downhole operations. However, when a wet condition is combined with high temperature, most high-temperature polymers and their composites behave very differently from their original dry state because of severe hygrothermal or hydrolytic degradation. In many cases, oilfield service tools are required to perform in a hot-wet fluid condition at temperatures above 204°C and pressures above 70 MPa. These conditions present significant challenges to applications of polymers and composites downhole. Properly characterizing and fully understanding the HTHP hot-wet thermomechanical properties of various high-temperature polymers and composites based on an accurate, environmentally simulated HTHP mechanical test method is extremely important for successful applications.

This paper will present a newly developed HTHP in-situ mechanical test rig and the associated test method for high-temperature polymers and composites. The in-situ mechanical test rig has been performed successfully in a fluid and gas environment up to 204°C and 34.5 MPa. For the first time, true HTHP hot-wet tensile and compressive strengths of a high-temperature epoxy neat resin and selected high-temperature polymer composites have been determined in a real HTHP hot-wet environment in the HTHP in-situ test rig immediately after a period of the HTHP hot-wet exposure. These results are found to be very different from those determined by conventional environmental-mechanical test methods. The authors will briefly review the conventional environmental-mechanical test methods for polymers and composites based on current literature and test standards and will discuss how the new HTHP in-situ mechanical test methods can eliminate the problems with the conventional test methods and procedures.
Local Update of Object-Based Geomodels
Authors: Georgsen F. , Syversveen A. R. , Hauge R. , Tollefsrud J. I. , Fismen M.
Published: June 2014

A method for local updating of object-based facies models by further development of already existing software is presented. An existing facies realization is adjusted to match new well observations by changing objects locally or adding/removing objects if required. Parts of the realization which is not influenced by the new wells are not changed. Local update of a specified region of the reservoir can be performed, leaving the rest of the reservoir unchanged or with minimum change due to new wells.

The main focus in the method is on the algorithm implemented to fulfill well conditioning. The effect of this algorithm on different object models is presented through several case studies. These studies show how the local update consistently includes new information while leaving the rest of the realization unperturbed and thereby preserves the good history match.
Performance Enhancements of Viscoelastic Surfactant Stimulation Fluids with Nanoparticles
Authors: Crews James B. , Huang Tianping
Published: June 2014

High-molecular-weight crosslinked polymer fluids have been used to stimulate oil and gas wells for decades. These fluids exhibit exceptional viscosity, thermal stability, proppant transportability, and fluid leak-off control. However, a major drawback of crosslinked polymer fluids is the amount of polymer residue they leave behind. Polymer residue has been shown to significantly damage formation permeability and fracture conductivity. 1-3 Recently, viscoelastic surfactant (VES) fluids composed of low-molecular-weight surfactants have been used as hydraulic fracturing and frac-packing fluids. The surfactants structurally arrange in brine to form rod-like micelles that exhibit viscoelastic fluid behavior. VES fluids, once broken, leave very little residue or production damage. However, excessive fluid leak-off and poor thermal stability has significantly limited their use.

This paper will introduce newly developed, select nano-size crystals with unique surface charges and will explain how nanoparticle technology pseudo-crosslinks VES rod-like micelles together to improve the fluid loss control and proppant transport of VES fluids to a performance level similar to that of crosslinked polymer fluid. The nanoparticle pseudo-crosslinked VES micelle fluid develops a wall-building pseudo-filtercake on the face of porous media to control fluid loss. When internal breakers are used to degrade the VES micelle structures the leaked-off VES fluid and the pseudo-filtercake breaks into brine water and nanoparticles. Since the nanoparticles are very small and readily pass through the pores of greater than 0.1 md formations, they are flowed back with the produced fluids, and no internal or external "solids" damage is generated.

This paper will present laboratory data that shows how uniquely charged nanoparticles improve VES fluid rheology, leak-off control, and proppant suspension. Also presented are test results comparing nanoparticle enhanced VES to borate crosslinked guar polymer fluids. The mechanisms that enhance the performance of these fluids also will be discussed.
Parallel Streamline Simulation
Authors: Löf Henrik , Gerritsen Margot , Thiele Marco
Published: June 2014

We present an efficient strategy for parallelizing streamline (SL) simulators using shared-memory programming models and evaluate its performance. This is the first work to extensively address parallelization of streamline solvers. We consider shared-memory programming models because of their suitability for SL simulation and because of the need to sustain peak performance on the multi-core processor platforms of the future. We test our implementation on a 8-way Sun Opteron server, representative of the state-of-the-art shared memory systems in use in the industry, as well as the very recently released Sun Niagara II multi-core machine that has 8 floating point compute units on the chip.

We consider both static and dynamic load-balancing algorithms and take into account associated communication overhead and data locality issues. We apply our experimental parallel SL simulator to two examples: the first test case is taken from the 10th SPE comparative solutions project, and the second is representative of large industrial reservoir applications. We use simple, single-phase, linear flow physics in order to clearly distinguish between system-related and physics-related run time performance.

We found that by using a large amount of streamlines per thread the dynamic load balancing strategies built-in to OpenMP performed well as the average workload per thread is not very sensitive to workload variations between individual streamlines. On the Opteron system, we find parallel efficiencies ranging between 60 and 75 %. The sublinear speedup is mostly due to a low degree of data locality in the tracing stage and communication overhead in the mapping stage. In applications with more complex physics, the relative contributions of these stages will decrease. Thus we expect the parallel performance, which is already attractive, to be higher in most industrial applications. On the Niagara II, we obtain almost perfect linear scalability thanks to the lowered communication costs on these architectures. This result is all the more satisfactory considering that future server designs will be akin to this system.
Real Time Well Placement above a Tar Mat, Leveraging Formation Pressure While Drilling and Pyrolytic Oil-Productivity Index Technologies
Authors: Al-Salem Khalid M. , Al-Malki Said S. , Ahyed Rabea A. , Jones Peter J. , Neumann Peter M.
Published: June 2014

Recent development of a large oil field in the Eastern Province of Saudi Arabia achieved real time well placement above a tar mat by utilizing Formation Pressure While Drilling (FPWD) and Saudi Aramco's Pyrolytic Oil-Productivity Index (POPI). Placement of 6 ⅛ in. horizontal power water injector wells in close proximity above an impermeable, undulating, tar layer posed a unique geosteering challenge. Additionally, a heavy oil layer of varying thickness exists above the tar. The uncertainty was to determine at what vertical depth fluid mobility stopped and heavy oil and/or tar began in the high porosity/permeability reservoir.

The heavy oil/tar layer is undetectable with conventional real-time logging while drilling (LWD) measurements. Furthermore, new technology devices such as the 6 ⅛ in. NMR While Drilling tool were not available when the field was developed. A technique of combining FPWD with POPI provided a solution to identify and steer away from the immobile fluids, minimizing the risk of completing an injection well in an interval with low or no injectivity.

POPI collectively refers to pyrolytic methods developed by Saudi Aramco to identify and quantify tar from residual hydrocarbon staining on drill cuttings. Pyrolytic Oil-Productivity Index provides a direct assessment of the residual hydrocarbons present on rock samples and allows an accurate determination of the volume of tar over a wide range of concentrations. The business impact is to assist with geosteering horizontal injector wells in real time. Formation pressure while drilling and POPI results were integrated to confirm favorable fluid mobility and well paths were placed to take advantage of this knowledge. Initial tests showed high injectivity in all wells, which indicates that they were placed in the desired zone. This paper includes selected case studies demonstrating both entry into and steering away from impermeable tar layers.
Production Optimization for Second Stage Field Development Using ICD and Advanced Well Placement Technology
Authors: Maggs D. , Raffn A. G. , Porturas Francisco , Murison J. , Tay F. , Suwarlan W. , Samsudin N. B. , Yusmar W. Z. A. , Yusof B. W. , Imran T. N. O. M. , Abdullah N. A. , Mat Reffin M. Z. B.
Published: June 2014

The paper covers the application of new technology drilling and completions equipment in horizontal wells to maximize production and recovery in a thin oil rim reservoir. The parallel process applied to the engineering design, drilling and completion operations, real-time decisions, and results are presented.

As part of the second stage development of a mature oil field offshore Malaysia, a shallow target was identified. Initial engineering and reservoir studies suggested that three deviated wells or two horizontal wells would be required to develop the area. While the horizontal wells option was expected to have lower costs, the well construction was far more technically challenging. To ensure maximum production and recovery a 2,000ft lateral section was required, further detailed studies indicated that for the long lateral to be successful, well placement with respect to reservoir boundaries and fluid contacts, and open-hole sand screens of a high mechanical integrity would be critical. Additionally, in order to ensure even oil production and limit early water and gas production In-flow Control Devices (ICD) would be required as part of the completion.

The well was actively steered using a Rotary Steerable System (RSS), and Logging While Drilling (LWD) measurements including a deep azimuthal resistivity distance to boundary device. Drilling was very efficient with the well placed close to the top of the sand, avoiding shale contact that could cause screen plugging, and the required distance from fluid contacts. The Real-Time (RT) logs were used to select optimum settings for the adjustable ICD completion prior to running in hole. The completion was run without incident and when the well was placed on line, produced without water breakthrough and without requiring gas lift due to effective clean-up of the entire horizontal section. Production from the well has exceeded expectations and is currently over double that of traditional wells.

The application of advanced well placement technology and field adjustable ICD completions has enabled the economic development a small area of remaining hydrocarbon in a mature field, while maximizing production and recoverable reserves. Even with the increased technology cost, the overall project cost was 15% less than if standard well construction techniques had been applied. The accurate placement of the wellbore close to the upper shale and even production along the lateral due to the ICD completion has resulted in a more efficient reservoir sweep increasing recoverable reserves by ~100 MSTB.
The Kitina Mature Offshore Field Rejuvenation: Massive Multistage Hydraulic Fracturing, Long Reach Wells, Improved Oil Recovery Techniques
Authors: Tealdi L. , Obondoko G. , Isella D. , Baldini D. , Baioni A. , Okassa F. , Pace G. , Itoua-Konga F. , Rampoldi M.
Published: June 2014

Many West Africa Offshore Fields are maturing and operators are completing secondary targets in their wells to maintain the economic operation of their valuable assets. However, off-shore environment makes the capital expenditure associated to this kind of interventions of critical importance. It follows that the selection of the right and most remunerative activities is crucial.

In the Kitina Field, offshore Congo, deeper sands have been produced to economic depletion and reservoir studies allowed the determination of alternative production intervals for production maintenance. Large quantities of reserves can be found in low permeability, consolidated, formations as well as in very deep and remote culminations.

During the first semester of 2007, the Kitina field production increased of 160% reaching a production level lost since early 2004. This was achieved with a variegate set of actions on different reservoirs: 1st) infilling the Kitina South culmination with the long reach and ultra deep well KTM-SM5, 2nd) a massive multistage hydraulic fracturing campaign carried out on the three wells draining the low permeability 3A reservoir and 3rd) with the sweep optimization of the reservoir 1A.

Eight propped hydraulic fractures were placed in three re-completed, cased-hole wells with very significant production improvements. These represented the first applications in Congo of different technologies opening a wide range of further applications in similar environments.

The paper describes the 2007 and 2008 Kitina rejuvenation campaign with an eye to all the disciplines involved, from reservoir engineering and modeling, to operation geology, drilling and completion, production.

The papers focuses with more detail on the successful multi-stage hydraulic fracture campaign from the preliminary design and production forecast pre-job to the reservoir model history match and forecast phase post-job. Interesting reservoir engineering overviews of the future development of the field via improved and enhanced oil recovery techniques are also presented.
Real Option Theory Complements the Stage and Gate Process: the Value of Information
Authors: Azzarone D. , Bruni T.
Published: June 2014

Phased project management processes, also known as stage and gate management processes (SGMP), are widely used to macro and micro-manage projects from early evaluation, to sanctioning and close out. These tools tend to disassemble by discipline the activities and decisions disseminated along the life of a project and re-bundle them into standardized sequential phases, with the underlying intention to narrow down uncertainties and multiply the project value.

By virtue of the implicit set of routines and checks, SGMPs have successfully brought a great deal of discipline in the allocation of human and financial capital among competing prospects – albeit not enough. Uncertainty is the scapegoat our industry too often resorts to to justify otherwise inexplicable failures. The variability embedded in the oil and gas business (nature, raw materials prices, etc.) undeniably plays to the detriment of our industry's bottom line but it is not the only delinquent in the game. Ultimately, opportunities are passed over on account of inappropriate assessment of the value of uncertainty and of acquiring the information (Value of Information, VOI) necessary to narrow it down.

Finance-derived Real Options have long been proposed to guide investment decisions and overcome the limitations of NPV-based approaches. However, Real Options have failed to win proselytes because of undeniable mathematical complication and an ill-fated fame to be too volatile a concept to fit into 150-year old oil and gas industry.

A novel approach is presented that complements the structured framework of SGMPs with VOI evaluation. The result is a project management tool that preserves the merits of SGMPs while warranting improved financial discipline.
Coupled Well and Reservoir Simulation Models to Optimize Completion Design and Operations for Subsurface Control
Authors: Wan Jing , Dale Bruce A. , Ellison Tim K. , Benish Tim G. , Grubert Marcel A.
Published: June 2014

Ensuring long-term optimum completion performance is important for the economic development of any field. As fields are now developed with fewer wells and in more technically challenging environment, new technologies are required to provide guidance and quantify the impact of completion design. This paper presents a new methodology in coupling ExxonMobil's reservoir simulator and a detailed well hydraulics simulator that simulates reservoir, wellbore tubing and wellbore annulus flow simultaneously. Case studies indicate that unique completions opportunities in optimizing completions options, especially inflow control devices, are captured by using the modeling capabilities

Completion strategies frequently include provisions to 1) maintain a uniform production profile along the wellbore, 2) manage future risks (early water or gas breakthrough) and mitigate the potential for sand production, and 3) improve reservoir recovery. Completion options include open hole, cased hole, inflow regulation devices (inflow/flow control devices and inflow valves), sand screens, or pre-drilled liners. Different from nodal based wellbore simulation in a conventional reservoir simulator, the proposed coupled well and reservoir simulation provides not only detailed information on the tubing and annulus flow and associated pressure drops in and throughout all completion types, but also the impact of completions on short and long term reservoir flow and recovery. Studies have shown the importance in utilizing the coupled model in both history matching and model prediction when advanced completions are applied. The significance of this new coupled approach is its ability to capture both flow dynamics through various completion options and reservoir performance
Control-Relevant Upscaling
Authors: Vakili-Ghahani S. A. , Jansen J. D.
Published: June 2014

The conventional reason for upscaling in reservoir simulation is the computational limit of the simulator. However, we argue that, from a system-theoretical point of view, a more fundamental reason is that there is only a limited amount of information (output) that can be observed from production data, while there is also a limited amount of control (input) that can be exercised by adjusting the well parameters; in other words, the input-output behavior is usually of much lower dynamical order than the number of grid blocks in the model. Therefore, we propose an upscaling approach to find a coarse model that optimally describes the input-output behavior of a reservoir system. In this control-relevant method, the coarse-scale model parameters are calculated as the solution of an optimization problem that minimizes the distance between the input-output behavior of the fine- and coarse-scale models. This distance is measured with the aid of the Hankel- or energy norms, where Hankel singular values are used as a measure of the combined controllability and observability of the system. The method is particularly attractive to scale up simulation models in flooding optimization and/or history matching studies for a given configuration of wells. An advantage of our upscaling method is that it intrinsically relies most heavily on those parameter values that directly influence the input-output behavior. It is a global method, in the sense that it relies on the system properties of the entire reservoir. It does not, however, require any forward simulation, neither of the full nor of the upscaled model. it also does not depends on a particular control strategy, but instead uses the dynamical system equations directly. A drawback, however, is its dependency on well positions, which implies that it should be (partially) repeated when those positions are changed. We tested the method on several examples and for nearly all cases obtained coarse scale models with a superior input-output behavior compared to common upscaling algorithms.
Multiscale Compositional Simulation of Naturally Fractured Resevoirs
Authors: Ramirez B. , Atan Safian , Kazemi Hossein
Published: June 2014

To obtain accurate descriptions of fluid flow in the reservoir, it is necessary to include detailed geological information on the scale of geocellular models. However, computation resources are often overwhelmed by the vast amount of information that geocellular models contain.

The multiscale approach presented in this paper is designed to include the detailed geological information into the flow calculations while making computations less expensive. The distinguishing characteristic of this paper lies on the procedure used to carry out the computations. The procedure splits the computation into pressure solution on a coarser grid and the saturations and compostions calculations on a very fine scale. This is based the physical and theoretical evidence that pressure effects travel at much higher velocities than saturation and composition fronts – thus, different scales on computation. Splitting up the computations through appropriate physical rules, the multiscale approach divides the computation of pressure propagation and convective processes like the saturation and composition fronts. The pressure propagation is diffusive in nature, while the saturation and composition computation being transport processes are convective in nature. These characteristics allow the computation of the solution at different scale levels. The multiscale approach of this paper is a sequential formulation based on a volume balance model using partial molar volumes. It starts with a compositional pressure equation based on the overall components balance. Once the pressure solution is obtained, the total phase and component velocities are calculated on a fine scale to track the saturation and composition fronts.

The multiscale method begins with the use of coarse grid blocks, which contain numerous finer grid blocks (the geocellular scale). Flux calculations based on the total face velocities at the boundaries of the coarse grid blocks are used to set up the fine grid calculations for both the pressure and saturations within each coarse grid block for accurate tracking of the displacement fronts. The finer scale solution is subsequently employed to improve the accuracy of the coarse grid block boundary conditions. The scheme is intended to capture the fine scale physics of gravity, capillarity, and phase behavior interactions as well as the global effect of rock heterogeneity (the dual-porosity effects), pore structure, stratigraphy, and reservoir architecture.
Accelerating the Build up of Experience with a View to the Imminent Big Crew Change
Authors: Bos C. F. M. , Berkhout A. J. , Currie P. K. , Weijermars R.
Published: June 2014

This paper describes a number of features of the E&P sector that impact on the staff qualities and attitudes required to optimally run E&P projects. The first is that the E&P sector, when compared to other sectors in the industry, has to face relatively high levels of uncertainty in its project outcomes. This is due mainly to data sparsity, technological depth, multidisciplinary breadth and business process complexity. Second, in order to survive in the international arena, E&P companies in essence compete on their ability to attract, develop and retain scarce human talent. Managing the above uncertainties puts exceptional demands on employee skills and internal business processes. It is argued that the gap between the required and available skills pool is widening and that, consequently, the sector is increasingly becoming a human talent constrained industry. A third feature therefore is that relatively more resources should be invested in continuing education to turn experience into deeper insight for improved performance. We postulate that with a properly trained workforce the executive mandates given to staff should be made more flexible at their local (disciplinary, business-unit, asset etc.) level, but more stringent at the global (overall corporate value chain, context) level.

When relating the above considerations to the imminent "big crew change", one should grasp this perspective as an opportunity to revisit the E&P sector's traditional approach to education. This paper describes the results of three years experience with a new executive training program for midcareer E&P professionals. It is designed to achieve, within twelve months, a quantum leap in their integration and abstraction skills, enabling them to solve efficiently complex managerial problems much earlier than traditional training programs. The course focuses on E&P decision-making under uncertainty using a comprehensive definition of added value. Students learn to integrate the pertinent information, and switch between abstraction and integration levels as a function of the decision to be made. Mastering this skill is normally achieved after many years of industry experience. The course could be labeled "the MBA for E&P professionals', however with both feet firmly on technical ground. The results are remarkable. Graduates are ready to assume responsibility as E&P asset and portfolio manager.
A Model Integrating Surface to Subsurface Models under Uncertain Conditions, for Optimizing Production in Santa Barbara and Pirital Fields, Venezuela
Authors: Rodríguez Vera Rosa Angélica , Muziotti Cesar , Caraballo Nelson
Published: June 2014

Located at the northern area of Monagas state, Venezuela is the Santa Barbara and Pirital Fields; known to be two of the principle hydrocarbon fields in the country. Since their discovery, several characterization studies have been done for improving the understanding of its complex geologic structure and fluid column distributions; which vary greatly within each of the eight, independently modeled, sectors of the two fields.

Opportunities for improving exploitation plans, of these fields, have been identified based on characterization studies. Accordingly, It was realized the importance of evaluating different scenarios of hydrocarbon production, considering the unique characteristics of each of the eight reservoir sectors, as well as the surface installations capacities for handling production in the short, medium and long terms; taking into account the different levels of risk and uncertainties.

This article presents the development of a subsurface-surface model for the evaluation of multiple production scenarios, taking into account the reservoir characteristics, well bore design and surface installations in an integrated manner scoping the unexpected out of plan deviations that was not considered in the initial planning process, as well as the inherent uncertainties of the models used for designing the exploitation plan.

This model allows the selection of the most adequate infrastructure for handling Oil and Gas production, based on the reservoir behavior over time and considering the margin of error as a function of the possible risk and uncertainties at the reservoir level as well as delays in drilling future wells and variations in the produced hydrocarbon densities. The results of this model will finally be used for the economic evaluation that decides on the profitability of the projects associated to these fields.

This article will focus on the procedure of integrating the different surface-subsurface model components supported by a case history from the area.
Optimizing Wireline Gun System Design and Perforating Performance for Very Late Changes in a Gulf of Mexico HPHT Deepwater Well
Authors: Sabbagh L. , Blalock D. , Melvan J. , Leung H.
Published: June 2014

Thunder Horse field, a new subsea development in 6,000 ft of water in the Gulf of Mexico (GOM) has stacked consolidated sandstone reservoirs that occur at 20,000 to 30,000 ft subsea with pressures of 14,000 to 18,000 psi, temperatures of 190 to 270°F, and mean rock strengths of 4,000 psi. The reservoirs do not require sand control and are completed with perforated casing. Four wells have been completed, perforated, and cleaned up since 2004 using drillship Discover Enterprise and a completion workover riser. The 2004 flowtest in Thunder Horse was the first time the industry produced hydrocarbons to surface from the GOM HPHT environment. The wells are normally completed with a 7-in. liner and perforated with ⅜-in. HSD wireline guns with deep penetrating charges. In 2006, as a result of drilling problems, a 4 ½-in. production liner was cemented in the 8 ½-in. hole. To achieve a productivity index and skin factor close to the original design, it was necessary to perforate using 2 ⅞-in. HSD guns. The tight tolerance between the fired guns and the pipe ID created an additional challenge. Extensive analysis, design, and yard testing revealed that the well could be safely perforated using 2 ⅞-in. HSD guns with the new enhanced deep penetrating charges and that this could deliver better perforation performance than the original gun system. The results from the well's cleanup program indicated an even better perforation efficiency than observed earlier. Downhole permanent gauges were essential to minimize underbalance conditions during perforating to prevent gun and line damage. Perforating was done between cleanup flow stages. Bullheading partial wellbore volume reduced surface pressure during perforating. The gauges monitored wellbore pressure at the reservoir during the bullheading operations for signs of perforation plugging.
Linking Sequence Stratigraphy, Depositional Environment and Sedimentary Facies to Model the Sandstone 3D Architecture Within Palaeozoic Clastic Reservoirs, Saudi Arabia
Authors: Mohd Zain Nazhri , Khalifa Mohammad A. , Stanley Rowan J.
Published: June 2014

Paleozoic clastic sediments, comprising continental to transitional marine depositional environments, form excellent hydrocarbon reservoirs in Saudi Arabia. In order to develop a realistic dynamic model that can be used in reservoir performance prediction, a robust geological model is required. Detailed modeling of sand accumulations, their lateral continuity and vertical stacking patterns is needed to capture reservoir heterogeneity at all wavelengths.

To build an understanding of the sandstone ‘lumbing’ within the reservoirs, the Depositional Related Environment Architecture Modelling (DREAM) workflow is invoked. Initially, the fabric of the medium-to-long dimension gross depositional environments is described in 3D. The distribution resides within the envelope of a sequence stratigraphic structural framework that links the main time-correlative boundaries. This model captures the progradational and retrogradational depositional behaviour and employs a stochastic distribution process to address population uncertainties. With the broad-scale environments defined, a subsequent step involves the distribution of short-to-medium scale sedimentary facies conditioned to the environment model. Lateral probability distribution maps and vertical proportion curves, combined with geological templates, are invoked within each environment to ensure that the facies distributions conform to as many observable and analogue trend constraints as possible.

In this paper, the DREAM workflow was applied for two case studies and the results are presented. The output models combine the structural framework based on seismic and sequence stratigraphic interpretation principles with linked environment and facies distributions.
Angsi K–Sand Production Performance: A Case History of Hydraulically Fractured Retrograde Gas Condensate Reservoir
Authors: Othman Mohamad , Yang Juhari , Chong Mizan Omar , Zakaria M. Sukri , Ali Bohlool Asgar , Cheng Cheong Boon
Published: June 2014

Angsi K-sand is the first tight gas reservoir development in Malaysia, developed in 2002 to meet an increasing domestic gas demand. K-sand is high temperature (320 °F), multi-layered over pressured retrograde gas condensate reservoirs ranging from 10-90ft net thickness and permeability of 0.1 – 3.0 mD. It was developed through multi-staged propped hydraulic fracturing to improve well deliverability and to mitigate productivity impairment due to condensate dropout near the wellbore. In general, initial gas production from these wells exceeded expectation with condensate level significantly higher than initially anticipated in the development plan. However, several wells exhibited relatively faster and steeper production decline with indications of productivity loss related to the liquid drop out in the vicinity of the wellbore. Scale problem and proppant flow back were also observed at surface during clean-up of production facilities.

There are many challenges in managing this complex reservoir and ‘unconventional’ well performance in an area with a history of conventional gas well operation only. The main challenge is to develop operating strategies in producing these wells at sufficient rate and recovery to meet the short term gas commitment and provides sufficient return on the projects economics. The strategies adopted are flexible enough to face the decision making required by this type of reservoir under anticipated production operations. Additionally, these strategies are the key in identifying opportunities, defining uncertainties and developing specific plans to gather information to allow fast response. Based on actual performance and surveillance data, various changes to the original plan are being implemented. Active reservoir surveillance planning and execution were carried out to provide a better understanding of well behavior and the effect of strategies to the well performance.

This paper summarizes the reservoir management challenges, techniques and technologies applied to monitor and evaluate the reservoir performance and operating strategies.
How to Extend the Heptanes plus Fraction for Gas Condensate Systems for Use in Compositional Simulation
Authors: Hosein Raffie , McCain William D. , Jagai Tennyson
Published: June 2014

An accurate description of pseudo-component compositions and properties provides the heart of Equation of State predictions for gas condensate systems. Very often these extended experimental data are unavailable and are generated using mathematical relationships. The exponential and the three-parameter gamma distribution functions are the two most widely used models. Their development was based on the assumption of a continuous molar relationship for pseudo-components. However, experimental compositional data for gas condensate systems show discontinuities in this relationship at C8 and C13.

The above models when applied to extend the C7+ fraction under predict the C8 mole percent and over predict the C12 mole percent due to discontinuities in the molar relationship at C8 and C13. The Average Absolute Deviation between the predicted and experimental C8 and C12 data were both greater than 25 percent. The two coefficient method described by Ahmed et al., when applied, took care of the discontinuity at C8. The deviation was less than 10 percent. However the C12 fraction had a deviation greater than 25 percent. These results show that existing schemes were not designed to take care of these discontinuities and should be used with extended experimental data beyond C13 for a more accurate description of the pseudo-component composition.

The "Four Coefficient" model described in this study takes care of the discontinuities in the molar relationship at both C8 and C13. The Average Absolute Deviation between the predicted and experimental compositions is less than 12 percent. This model can be quite easily included in Equation of State packages for a more accurate description of compositions for gas condensate systems. A partial analysis beyond the C7 fraction is not required with this model.
Oil and Gas Expertise for Geothermal Exploitation: The Need for Technology Transfer
Authors: Falcone Gioia , Teodoriu Catalin
Published: June 2014

Renewable energy is seen as the future source to meet the world's growing demand, with geothermal resources offering a constant and independent supply.

Over the past century, the oil and gas sector has developed high level technologies for the exploitation of hydrocarbon reservoirs and this expertise should be directly transferrable to geothermal exploitation.

In contrast to hydrocarbon developments, geothermal projects typically only become economic after decades of operation, which implies a long period of debt service before costs can be recovered from the sale of energy in the form of heat, electricity or a combination of both. Thus, the technology transfer between the petroleum and geothermal sectors has not been as efficient as initially hoped for.

This paper begins with a review of the principles and uses of geothermal energy in today's sustainable energy scenario, from District Heating systems to the more recent Hot Dry Rock (HDR) concept. As exploiting HDR resources becomes more economic, the geothermal energy resources of countries like the U.S. could meet domestic demand for electricity for thousands of years. The challenges presented by HDR projects around the world are discussed, with a special focus on those aspects of geothermal exploitation that overlap with the oil and gas expertise, such as drilling and completions practices, the characterization of fluid flow through porous media and in wellbores and reservoir fracturing issues. The comparison shows how hydrocarbon exploration and production complements that of geothermal exploitation and identifies technical areas where future research efforts should be addressed to enhance the technology transfer between these energy sectors.
Impact of Multilateral Wells on Oil Recovery in an Oil Rim Field Development Using Multilateral Wells with Natural Gas Lift and Inflow Control Devices in a Fractured Carbonate Reservoir
Authors: Iyamu O. , Coll C. , Bouhafs C. , Butter M. , Bejaoui R. , King P.
Published: June 2014

Use of sector models with fine grids that preserve the boundary conditions of the full field model has been of particular benefit to studying well coning behaviour for the different well geometries while allowing detail studies of the physics of flow and to optimize production rate by different well designs.

The objective of this project was to carry out simulation studies to investigate the pattern of gas coning and water encroachment for a bilateral well with the primary aim of producing oil from a reservoir overlain by a large gas cap in Field A. High precision local refinement studies in the simulation model were undertaken to help place the wells and optimize the completion design at the same time capturing the global field behaviour. This methodology was also used to properly simulate multilateral wells containing inflow control devices, allowing for pressure losses along the wellbore to be equalized and to minimize gas and water coning.

Prior to undertaking the simulation studies, several sensitivities were carried out to determine how other parameters such as boundary conditions and grid refinements could affect the output of near well bore models. By taking advantage of the time savings resulting from the generation of reduced fine grid models, several simulations were run to investigate the impact of different well configurations and operations due for instance to close/opening of valves or laterals.

The simulation studies resulted in the determination of the pattern of gas coning, water encroachment, optimum vertical placement of the oil lateral and the orientation of the gas lateral as they affect total recovery. The use of Inflow Control Device (ICD) was determined to be of benefit especially in controlling water and gas influx while providing a uniform production profile along the wellbore that delay gas and water coning and this is being incorporated now in the plan of development.
Real-Time Water Detection and Flow Rate Tracking in Vertical and Deviated Intelligent Wells with Pressure sensors
Authors: Aggrey George , Davies David
Published: June 2014

Value addition via real-time reservoir monitoring and optimisation is one of the main drivers for the increasing implementation of intelligent (I-)well completions. The benefits from these more expensive completions will be realized through increased reserves generated by increased drainage efficiency and reduction in well numbers and intervention frequency. A more rigorous exploitation of the real time production data is necessary to fully achieve this objective.

We previously showed that water influx time and source could be detected in horizontal wells in real time1. Extension of this technique will be shown to allow confident detection of water influx in vertical or deviated, multi-zone and/or multi-lateral I-well completions. The source of water influx into the well and the zonal fluid contribution will be quantified, allowing this unwanted fluid's production to be reduced. Knowledge of the influx time and source permits both production optimisation and improved reservoir sweep efficiency; processes that increase the well's productive life and reserves.

It will be demonstrated that monitoring of the pressure drop, called dP trending in this paper, across multiple pressure sensors correctly located within a multi-zone vertical or deviated I-completion can identify the time and location of the water influx into the well. We will discuss the necessary conditions to ensure clear identification of these parameters.

The concept of "Normalised Pressure Drop Signatures" will be introduced. It has proven to be particularly valuable for water influx detection and zonal flow rate monitoring purposes. The concept will be tested with data generated from a synthetic model of a 4-zone, deviated, I-well completion and with real-field data from an instrumented North Sea well.