bluuebunny/crossref_metadata_2025 huggingface dataset:
Pressure Drop versus Flow Rate Profiles for Power-Law and Herschel-Bulkley Fluids
Authors: Omosebi A. O. , Adenuga K. A.
Published: June 2014

The rheological behavior of drilling fluids under static and dynamic drilling conditions is a major concern to both service companies and operators. Most often, a shear stress-shear rate graphical relationship, characteristic of the type of drilling fluid, is used to understand this behavior. Power-law fluids, because of their rheological properties, are majorly used as drilling fluids; the shear stress-shear rate proportionality is non-linear, rather a hyperbolic relationship exists. Herschel-Bulkley fluids, on the other hand, behaves like power-law fluids at low shear rate but deviates from this behavior at high shear rate, demonstrating linear relationship between shear stress and shear rate; a characteristic typical of Bingham plastic fluids.

In order to improve drilling operation with these fluids, understanding pressure drop-flow rate behavior in the annulus is necessary. Using the constitutive equations characterizing these fluids as well as differential equations describing the velocity distribution in the annulus, this paper presents mathematical relationships between mud circulating rate and the associated pressure drop for Power-law and Herschel-Bulkley fluids flowing between parallel plates and through cylindrical pipes. Subsequently pressure drop versus flow rate profiles and annular velocity distributions where generated.

The results show perfect profile-match between the conventional shear stress-shear rate techniques and the pressure drop-flow rate profiles. The outcome of this work can be used to develop pressure drop versus flow rate profiles and annular velocity distribution during drilling. These profiles can then be used to determine pressure drop in the entire drillstring when circulating at any rate. Also, the minimum pump power rating can be estimated from the results of this work. This work is applicable in improving drilling and well completion operations.
Evaluating First Eagle Ford Shale Gas Well—Case History from Northern Mexico
Authors: Araujo Oscar , Lopez-Bonetti Elias , Sierra Jose
Published: June 2014

Northern Mexico has the first major non-associated gas producer basin in the country. However, unconventional reservoirs (mostly very low-permeability shale gas and oil formations) have not been produced so far in this area. These types of reservoirs are located in sedimentary environments where rocks have a high organic-rich content that, when subjected to pressure and temperature conditions, transform this matter into oil and gas. Stimulating a source rock is relatively a new phenomenon in the oil and gas industry. Because these source rock formations have very low permeability, massive hydraulic fracturing stimulation treatments are required to produce at economical rates. Experience and knowledge in drilling and completing wells in this type of reservoir have increased in the last decade. New technologies to evaluate this type of formation and post-production studies have significantly improved, offering better completion methods and techniques.

The Eagle Ford formation in Mexico is located in the northern portion of the country and is considered an extension of the Eagle Ford formation that crosses southern Texas in the United States; during June 2011, production from this US formation was 636 MMscf/D and 97,000 bbl/D.

For the completion of this subject well, which was drilled horizontally, the evaluation techniques, completion plan, and stimulation design were performed using local experience acquired in unconventional reservoirs (tight oil and tight gas) along with experience from the US in shale gas and oil shale formations.

This work shows how this type of formation was identified through several studies, completion was designed and executed, and the fracture treatments were optimized, as well as production matching and forecasting results. This was all performed in the context of an operation that had never been performed in Mexico.
Analysis of Pressure Build-Up and Flow Test Data
Authors: Matthews C.S.
Published: June 2014

Methods of using pressure build-up or flow tests to estimate formation permeability, formation pressure and well damage are reviewed. A number of phenomena which cause actual pressure build-up behavior to differ from the idealized case, such as the effects of boundaries, skins, inhomogeneities, partial penetration and two-phase flow, are discussed. It is concluded that the same method of analysis of build-up curves can be applied with slight modification to oil reservoirs, gas reservoirs and reservoirs producing both oil and gas. The calculations can be carried out on a form sheet, a copy of which is included in the paper. Examples are worked out for four different types of reservoirs.

Introduction

Although the basic theory of pressure build-up behavior in wells was developed many years ago, important contributions since that time have extended the original applicability to a much wider variety of situations. The purpose of the present paper is to summarize the present status of pressure build-up theory and of its applicability.

The approach in this paper will be to start with the simplest type of pressure build-up curve and to show how reservoir rock properties, reservoir fluid properties and wellbore conditions tend to distort the idealized picture. Methods for taking these distortions into account and for determining values of reservoir formation properties from build-up curves will then be considered.
Design and Well Parameters Effects on Run Life of Sucker Rod Pumps (SRP): A Statistical Study for Adiyaman - Turkey
Authors: Ergun Ender
Published: June 2014

After 1859, sucker rod pump was invented commercially by C. E. Drake1, it was used vast majority of wells throughout the world. Thus, it became an oil symbol which comes to mind first for people even who are not engaged in this industry. Although SRPs are installed in about 90% of oil wells in USA, half of wells, 110 are installed by SRP in Adiyaman. Oil and water production is 13,000–13,500 bbl/day and amount of oil is 3,000–3,500 bbl/day.

This study explained that effects of parameters, which are related to reservoir and design, to the mean time between failures (MTBF) of pumps. In this controlled test, MTBF is dependent variable and well parameters are independent variables such as pump diameter, water cut, pump depth, stroke per minute(SPM), salinity and flow rate. These independent variables are examined one by one and completely. All data are taken from 384 well operations in 77 wells and spanned 3.5 years. Index Terms – Sucker Rod Pumps, SRP, Run Life, MTBF, Design Parameters, Well Parameters
Novel Jet-Pump Application Enables Water Flood Project for a Sour Carbonate Reservoir in the Sultanate of Oman
Authors: Al-Hosni F. , Lanier G. H.
Published: June 2014

A sour carbonate reservoir has been identified for water flooding to improve hydrocarbon recovery. The field is situated in the South of Oman and was discovered by PDO in 2005. Production began in 2007 and contains crude oil with 30° API oil gravity and solution GOR of 80 Sm3/m3, as well as, sour fluid contaminants of 5 mol% H2S and 3 mol% CO2. Reservoir water fluid samples confirm salinity is more than 220,000 mg/L chloride ions. While the reservoir is over-pressured at more than 600 bara with a bubble-point pressure of 140 bara, reservoir pressure continues to decline during the initial depletion phase of the field development.

Although water flooding will arrest pressure decline in the reservoir, due to subsurface challenges and uncertainties, artificial-lift is considered a key project requirement during the expected field life. Initially, reservoir water salinity is expected to contribute to an increased risk of salt precipitation and related flow assurance concerns as the water flood approaches the production wells. In addition, expected producing conditions are considered to be extremely corrosive.

This paper will provide a summary of the expected field conditions, water flood project background and key artificial-lift application challenges including the proposed conceptual well completion designs to support the field development. A summary of artificial-lift selection, design and implementation strategy will be explained including objectives, scope and results of the recent jet-pump field trial. Finally, a brief summary of the key conclusions and plans forward will be shared.
Consideration of Voidage-Replacement Ratio in Well-Placement Optimization
Authors: Awotunde Abeeb A. , Sibaweihi Najmudeen
Published: June 2014

Determining the optimum location of wells during waterflooding contributes significantly to efficient reservoir management. Often, the voidage-replacement ratio (VRR) and net present value (NPV) are used as indicators of performance of waterflood projects. In addition, VRR is used by regulatory and environmental agencies as a means of monitoring the impact of field-development activities on the environment, whereas NPV is used by investors as a measure of profitability of oil and gas projects. Over the years, well-placement optimization has been performed mainly to increase the NPV. However, regulatory measures call for operators to maintain a VRR of unity (or close to unity) during waterflooding.

A multiobjective approach incorporating NPV and VRR is proposed for solving the well-placement-optimization problem. We present the use of both NPV and VRR as objective functions in the determination of optimal location of wells. The combination of these two in a multiobjective optimization framework proves to be useful in identifying the trade-offs between the quest for high profitability of investment in oil and gas projects and the desire to satisfy regulatory and environmental requirements. We conducted the search for optimum well locations in three phases. In the first phase, only the NPV was used as the objective function. The second phase had the VRR as the sole objective function. In the third phase, the objective function was a weighted sum of the NPV and the VRR. A set of four weights was used in the third phase to describe the relative importance of the NPV and the VRR, and a comparison of how these weights affect the optimized NPV and VRR values is provided.

We applied the method to determine the optimum placement of wells to three sample reservoirs: the first with a distributed permeability field, the second being a channel reservoir with four facies, and the third being a slightly heterogeneous reservoir. Two evolutionary-type algorithms—the covariance matrix adaptation evolutionary strategy (CMA-ES) and differential evolution (DE)—were used to solve the optimization problem. Significantly, the method illustrates the trade-off between maximizing the NPV and optimizing the VRR. It calls the attention of both investors and regulatory agencies to the need to consider the financial aspect (NPV) and the environmental aspect (VRR) of waterflooding during secondary-oil-recovery projects. The multiobjective optimization approach meets the economic needs of investors and the regulatory requirements of government and environmental agencies. This approach gives a realistic NPV estimation for companies operating in jurisdictions with a requirement for meeting a VRR of unity.
Toward Drilling Automation: On the Necessity of Using Sensors That Relate to Physical Models
Authors: Cayeux E.. , Daireaux B.. , Dvergsnes E.W.. W. , Florence F..
Published: June 2014

Current topside and downhole instrumentation at the wellsite has been developed to manually conduct drilling operations. The emergence of automatic drilling-analysis software shows the limitations of today's measurement capabilities. It is therefore time to analyze the requirements for on-site instrumentation to implement new, efficient drilling-automation technologies.

On one hand, drilling is facing more and more difficult conditions with narrow geopressure windows, deepwater, or high-pressure/high-temperature (HP/HT) conditions. On the other hand, unconventional hydrocarbon reserves may require a considerable amount of wells to be profitable. Drilling automation, by means of smart safeguards, automatic safety triggers, managed-pressure drilling (MPD), and ultimately complete or semiautonomous drilling rigs, can provide the solution to safely construct wells in these challenging settings.

The common denominator for the vast majority of drilling-automation solutions is the use of physical models of the drilling process in the form of heat-transfer, mechanical, and hydraulic models. By analyzing the requirements of those models for necessary boundary conditions, it is possible to derive which measurements should be made both at surface and downhole to obtain stable and accurate calculations. This analysis also provides a way to estimate the necessary accuracy of the boundary conditions to ensure reaching the target control tolerance.

By use of the boundary-condition analysis, it is possible to derive precisely which measurements should be performed and where they should be performed. As a result, a typical organization of sensors that is compatible with the implementation of drilling-automation solutions is derived.
Setting Free the Bear: The Challenges and Lessons of the Ursa A-10 Deepwater Extended-Reach Well
Authors: Gradishar John , Ugueto Gustavo , van Oort Eric
Published: June 2014

This paper details the case history of the highly challenging extended-reach deepwater A-10 well, drilled in the Ursa (“Bear” in Latin) prospect in the Gulf of Mexico (GOM). This 30,000-ft well, drilled from the Ursa tension-leg platform (TLP) at a vertical depth of 18,000 ft and a horizontal displacement (HD) of 20,000 ft, targeted the Yellow sand in the Ursa-Princess section of the greater Mars-Ursa basin. During the drilling of the original hole (OH), two subsequent sidetracks, and two mechanical bypasses, a number of significant hole problems materialized that caused extensive nonproductive time (NPT) and an associated cost overrun. These problems were clearly associated with the drilling of a complex well that combined a high-deviation and extended-reach wellbore with a very narrow and pressure-depleted drilling window, characteristic of the GOM's challenging geopressured environment. In all, at least five independent borehole-failure mechanisms were encountered while drilling the OH and its successive sidetracks/bypasses, which were exacerbated by an additional complicating factor:

Lost circulation in natural fractures, ultimately responsible for the loss of the Ursa A-10OH Lost circulation in induced fractures, with associated heavy mud losses Borehole fatigue, caused by stress cycling on weak formations caused by annular-pressure fluctuations Borehole instability caused by too-low downhole hydrostatic pressure, responsible for the loss of Ursa A-10 Sidetrack 1 Borehole instability caused by an in-situ fractured formation that proved hard to stabilize on wells Ursa A-10 Sidetrack 1 Bypasses 1 and 2, and ultimately forced the well to be completed in shallower Magenta sands Complicating factor: barite sag of synthetic-based mud in high-deviation wellbores, which led to exacerbation and complication of the previous failure mechanisms

An extensive lookback study was carried out on the Ursa A-10 well, leading to the development of several important lessons learned and best practices [e.g., for hole cleaning, equivalent-circulating-density (ECD) management, sag control], and to the development of new systems (including novel, sag-resistant synthetic-based-mud formulations). A succinct overview of the Ursa A-10 case history and a comprehensive summary of its learnings are provided here to help the future drilling of extended-reach wells in geopressured, low-margin deepwater environments.
A Generalized Framework Model for the Simulation of Gas Production in Unconventional Gas Reservoirs
Authors: Wu Yu-Shu , Li Jianfang , Ding Didier-Yu , Wang Cong , Di Yuan
Published: June 2014

Unconventional gas resources from tight-sand and shale gas reservoirs have received great attention in the past decade around the world because of their large reserves and technical advances in developing these resources. As a result of improved horizontal-drilling and hydraulic-fracturing technologies, progress is being made toward commercial gas production from such reservoirs, as demonstrated in the US. However, understandings and technologies needed for the effective development of unconventional reservoirs are far behind the industry needs (e.g., gas-recovery rates from those unconventional resources remain very low). There are some efforts in the literature on how to model gas flow in shale gas reservoirs by use of various approaches—from modified commercial simulators to simplified analytical solutions—leading to limited success. Compared with conventional reservoirs, gas flow in ultralow-permeability unconventional reservoirs is subject to more nonlinear, coupled processes, including nonlinear adsorption/desorption, non-Darcy flow (at both high flow rate and low flow rate), strong rock/fluid interaction, and rock deformation within nanopores or microfractures, coexisting with complex flow geometry and multiscaled heterogeneity. Therefore, quantifying flow in unconventional gas reservoirs has been a significant challenge, and the traditional representative-elementary-volume- (REV) based Darcy's law, for example, may not be generally applicable.

In this paper, we discuss a generalized mathematical framework model and numerical approach for unconventional-gas-reservoir simulation. We present a unified framework model able to incorporate known mechanisms and processes for two-phase gas flow and transport in shale gas or tight gas formations. The model and numerical scheme are based on generalized flow models with unstructured grids. We discuss the numerical implementation of the mathematical model and show results of our model-verification effort. Specifically, we discuss a multidomain, multicontinuum concept for handling multiscaled heterogeneity and fractures [i.e., the use of hybrid modeling approaches to describe different types and scales of fractures or heterogeneous pores—from the explicit modeling of hydraulic fractures and the fracture network in stimulated reservoir volume (SRV) to distributed natural fractures, microfractures, and tight matrix]. We demonstrate model application to quantify hydraulic fractures and transient flow behavior in shale gas reservoirs.
Optimization Algorithms Based on Combining FD Approximations and Stochastic Gradients Compared With Methods Based Only on a Stochastic Gradient
Authors: Yan Xia , Reynolds Albert C.
Published: June 2014

Optimization algorithms that incorporate a stochastic gradient [such as simultaneous-perturbation stochastic approximation (SPSA), simplex, and EnOpt] are easy to implement in conjunction with any reservoir simulator. However, for realistic problems, a stochastic gradient provides only a rough approximation of the true gradient, and, in particular, the angle between a stochastic gradient and the associated true gradient is typically far from zero even though a properly computed stochastic gradient usually represents an uphill direction.

This paper develops a more robust optimization procedure by replacing the components of largest magnitude of the stochastic gradient with a finite-difference (FD) approximation of the pertinent partial derivatives. In essence, the objective of the method is to determine which components of the unknown true gradient are most important and then replace the corresponding components of the stochastic gradient with more-accurate FD approximations. This modified gradient can then be used in a gradient-based optimization algorithm to find the minimum or maximum of a given cost function. Our focus application is the estimation of optimal well controls, but it is clear that the method could also be used for other applications, including history matching.
A Semi-Implicit Approach for Integrated Reservoir and Surface-Network Simulation
Authors: Liang Jialing , Rubin Barry
Published: June 2014

Conventionally, methods of coupling reservoirs and surface networks are categorized into implicit and explicit approaches. The term "implicit coupling" indicates that the two simulators solve unknowns together, simultaneously, or iteratively, whereas "explicit coupling" indicates that the two simulators solve unknowns sequentially and exchange their boundary conditions at the last coupled time tn.

The explicit approach is straightforward to implement in existing reservoir and surface-network models and is widely used. Explicit coupling does have drawbacks, however, because well rate and pressure oscillations are often observed.

In this paper, a new semi-implicit method for coupled simulation is presented. This technique stabilizes and improves the accuracy of the coupled model. The "semi-implicit coupling" overcomes the problems found in explicit-coupling methods without requiring the complexity of a fully implicit coupled model.

The new approach predicts inflow-performance-relationship (IPR) curves at the next coupled time tn+1 by simultaneously conducting well tests for all wells in the reservoir before actually taking the required timestep. All wells first flow simultaneously to the next coupled time tn+1 with the well rates unchanged from the last coupled timestep. The timestep is rewound, and all well rates are reduced by a uniform fraction and then simultaneously flow again to tn+1. By extrapolating the resulting well pressures, the well's shut-in pressures at time tn+1 are determined, and thus, straight-line IPRs are produced. The new IPR curves approximate better each well's drainage region at tn+1 and each well's shut-in pressure at tn+1 which helps to stabilize the explicitly coupled model.

The new coupling technique normally does not require iteration between the reservoir and surface network and normally has the stability and accuracy characteristics of an implicitly coupled approach. Because the well tests already account for individual well-drainage regions, an explicit knowledge of the well-drainage region is not required. Because of the stabilized IPR, the approach also was found to reduce the overall computational time compared with explicit coupling.

Applications of the new approach are presented that show significant improvements surpassing explicit coupling in both stability and accuracy.
Reduced-Order Modeling for Compositional Simulation by Use of Trajectory Piecewise Linearization
Authors: He Jincong , Durlofsky Louis J.
Published: June 2014

Compositional simulation can be very demanding computationally as a result of the potentially large number of system unknowns and the intrinsic nonlinearity of typical problems. In this work, we develop a reduced-order modeling procedure for compositional simulation. The technique combines trajectory piecewise linearization (TPWL) and proper orthogonal decomposition (POD) to provide a highly efficient surrogate model. The compositional POD-TPWL method expresses new solutions in terms of linearizations around states generated (and saved) during previously simulated “training” runs. High-dimensional states are projected (optimally) into a low-dimensional subspace by use of POD. The compositional POD-TPWL model is based on a molar formulation that uses pressure and overall component mole fractions as the primary unknowns. Several new POD-TPWL treatments, including the use of a Petrov-Galerkin projection to reduce the number of equations (rather than the Galerkin projection, which was applied previously), and a new procedure for determining which saved state to use for linearization are incorporated into the method. Results are presented for heterogeneous 3D reservoir models containing oil and gas phases with up to six hydrocarbon components. Reasonably close agreement between full-order reference solutions and compositional POD-TPWL simulations is demonstrated for the cases considered. Construction of the POD-TPWL model requires preprocessing overhead computations equivalent to approximately three or four full-order runs. Runtime speedups by use of POD-TPWL are, however, very significant—up to a factor of 800 for the cases considered. The POD-TPWL model is thus well suited for use in computational optimization, in which many simulations must be performed, and we present an example demonstrating its application for such a problem.
Unstructured Cut-Cell Grids for Modeling Complex Reservoirs
Authors: Mallison Brad , Sword Charles , Viard Thomas , Milliken William , Cheng Amy
Published: June 2014

Effective workflows for translating Earth models into simulation models require grids that preserve geologic accuracy, offer flexible resolution control, integrate tightly with upscaling, and can be generated easily. Corner-point grids and pillar-based unstructured grids fail to satisfy these objectives; hence, a truly 3D unstructured approach is required. This paper describes unstructured cut-cell gridding tools that address these needs and improve the integration of our overall reservoir-modeling workflows.

The construction of simulation grids begins with the geologic model: a numerical representation of the reservoir structure, stratigraphy, and properties. Our gridding uses a geochronological (GeoChron) map from physical coordinates to an unfaulted and unfolded depositional coordinate system. The mapping is represented implicitly on a tetrahedral mesh that conforms to faults, and it facilitates accurate geostatistical modeling of static depositional properties. In the simplest use case, we create an explicit representation of the geologic model as an unstructured polyhedral grid. Away from faults and other discontinuities, the cells are hexahedral, highly orthogonal, and arranged in a structured manner. Geometric cutting operations create general polyhedra adjacent to faults and explicit contact polygons across faults. The conversion of implicit models to explicit grids is conceptually straightforward, but the implementation is nontrivial because of the limitations of finite precision arithmetic and the need to remove small cells formed in the cutting process.

In practice, simulation grids are often constructed at coarser resolutions than Earth models. Our implementation of local grid coarsening and refinement exploits the flexibility of unstructured grids to minimize upscaling errors and to preserve critical geologic features. Because the simulation grid and the geologic model are constructed by use of the same mapping, fine cells can be nested exactly inside coarse cells. Therefore, flow-based upscaling can be applied efficiently without resampling onto temporary local grids.

This paper describes algorithms and data structures for constructing, storing, and simulating cut-cell grids. Examples illustrate the accurate modeling of normal faults, y-faults, overturned layers, and complex stratigraphy. Flow results, including a field-sector model, show the suitability of cut-cell grids for simulation.
Unconstrained Voronoi Grids for Densely Spaced Complex Wells in Full-Field Reservoir Simulation
Authors: Fung L.S.K.. S.K. , Ding X.Y.. Y. , Dogru A.H.. H.
Published: June 2014

Accurate representation of near-well flow is an important subject matter in reservoir simulation. In today's field-scale reservoir simulation, cell-centered structured grids remain the predominant practice. Typically, well-inflow performance of the perforated cells is connected to the finite-volume solution by means of well indices that may not be well-defined when the wellbore intersects the finite-volume cells in a complex trajectory. Fine gridding is also required to resolve the flow dynamics in the near-well regions. Strong grid-orientation sensitivities can also contribute to the numerical errors and may require significant local grid refinement to alleviate. There are ongoing resesarch-and-development (R&D) efforts on applying unstructured grids to better represent the near-well flow in reservoir simulation, but their applications are mainly in single-well study or sector modeling with a few wells. Some of the reasons cited for this include (1) the lack of an effective, easy-to-use full-field complex well-gridding tool; (2) the lack of supporting unstructured workflow for full-cycle reservoir simulation; (3) the cost of unstructured-grid simulation; and (4) the availability of post-analysis and visualization tools for unstructured-grid simulation.

The paper describes a novel method to automatically generate unstructured grids that conform to complex well paths in field-scale simulation. The method uses a multilevel approach to place cells optimally within the solution domain on the basis of the “regions of interests.” The wellbore geometry is honored by means of the construction of a near-well grid that is complemented with multilevel quad-tree (Fig. 1) refinements to achieve the desired resolution in grid transition zones. The method includes an algorithm to remove small cells and pinching cells on the basis of local grid quality measures and cell prioritization to honor well paths. The gridding process forms a component of a production-level reservoir-simulation workflow. The use of unstructured grid results in computational savings by placing cells where the resolution is needed. An in-house massively parallel simulator is used to run the unstructured-grid models. Simulation examples for full-field applications with hundreds of complex wells by use of both structured grids and unstructured grids will be used to compare results, accuracy, and performance of the gridding method for reservoir simulation.
Development of an Analytical Injectivity Model for Non-Newtonian Polymer Solutions
Authors: Li Zhitao , Delshad Mojdeh
Published: June 2014

In applications of polymer flood for enhanced oil recovery (EOR), polymer injectivity is of great concern because project economics is sensitive to injection rates. In-situ non-Newtonian polymer rheology is the most crucial factor that affects polymer injectivity. There are several ongoing polymer-injection field tests in which the field injectivities differ significantly from the simulation forecasts. We have developed an analytical model to more accurately calculate and predict polymer injectivity during the field projects to help with optimum injection strategies.

Significant viscosity variations during polymer flood occur in the vicinities of wellbores where velocities are high. As the size of a wellblock increases, velocity smears, and thus polymer injectivity is erroneously calculated. In the University of Texas Chemical Flooding Simulator (UTCHEM), the solution was to use an effective radius to capture the “grid effect,” which is empirical and impractical for large-scale field simulations with several hundred wells. Another approach is to use local grid refinement near wells, but this adds to the computational cost and limits the size of the problem. An attractive alternative to previous approaches is to extend the Peaceman well model (Peaceman 1983) to non-Newtonian polymer solutions.

The polymer rheological model and its implementation in UTCHEM were validated by simulating single-phase polymer injectivity in coreflood experiments. On the basis of the Peaceman well model and UTCHEM polymer rheological models covering both shear-thinning and shear-thickening polymers, an analytical polymer-injectivity model was developed. The analytical model was validated by comparing results of different gridblock sizes and radial numerical simulation. We also tested a field case by comparing results of a fine-grid simulation and its upscaled coarse-grid model. A pilot-scale polymer flood was simulated to demonstrate the capability of the proposed analytical model. The model successfully captured polymer injectivity in all these cases with no need to introduce empirical parameters.
Control and Development of Simultaneous-Operations Drilling, Workover, and Well Services: Successful Case in La Hocha Field
Authors: Castañó Ricardo , Diaz Oscar , Cruz Ediberto , Ortiz Everardo , Rueda Henry , Herrera Andrea , Aldana Erwin , Gutierrez Wilian
Published: June 2014

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The operator company, committed to its performance in industrial safety, occupational health, the reduc tion of its environmental impacts and the protection of its ass ets, towards the year 2004, it de veloped its concurrent operation guidelines for places where two or more high-risk operations are carried out, which include drilling, completion, work-over, well-service activities, well production, and civil, mechanical and electrical works of facilities. This is so lely done to ide ntify all hazard s, evaluate and control all risk-taking in these activities to avoid the o ccurrence of incidents involving people, the environment and damage to company equipment.

It was necessary to conduct several activities at its production field, LA HOCHA 1 location, to apply our concurrent operation guidelines on that platform as a res ult of a production increase and the development of new projects.

The activities conducted on the same location, La Hocha 1, were:LH 9 well intervention using Flush By equipmentLH 7 well workover ServiceLH 1-LH 7-LH 8 LH 9 ProductionLa Hocha 25 DrillingCPF Construction.

Two purposes were defined on La Hocha concurrent operation plan; the first is handling, authority relations and responsibility in matters concerning HSE, and the second is to establish procedures and guidelines which must be implemented when various activities are conducted simultaneously including drilling or produc tion operations on a platform or a worksite which for this specific case was La Hocha 1.

After carrying out these concurrent activities, we were abl e to fulfill our propos ed goal of zero injuries to pe ople, no e nvironmental impact, no equipment damage, the fulfillment of all the plans prepared for each operation, and most of all recogni tion for the company for its excellent coordination and communication work performed during concurrent operations on La Hocha 1 Platform.
China Offshore HSE Management for Securing Platform Drilling Operations
Authors: Cheng Kun , Gokdemir Oktay M. , Cheng Zhong , Cetkovic Ivan , Li Yongjun , Li Shiguang
Published: June 2014

After experiencing severe weather events on offshore platforms in the Bohai Sea, China National Offshore Oil Corporation (CNOOC) adopted a health, safety, and environment (HSE) management initiative specifically for offshore platforms in that region. The event prevention and treatment measures adopted by CNOOC incorporate advanced management experience and hazard management technology with methods and characteristics unique to CNOOC. The HSE program controls risks of health, safety and environment risks during the process of drilling operations on offshore platforms, and treats mechanisms and causes of the operational risks equally with the detrimental accidents. To reduce risks and aid prevention, CNOOC’s HSE initiative is continuously enriched through by implementing precautionary measures.

This paper detail features of CNOOC’s HSE initiative, including accident prevention and treatment, risk reduction, and management control. The HSE platform adopts the management concept that accidents are preventable through full participation, different-leveled responsibility, programmed enforcement, and standardized scientific management method.
Environmental, Health, and Safety Management Information System Design and Implementation Planning for a Global E&P Company
Authors: Heinrich Anne
Published: June 2014

The Application

A global oil and gas exploration and production company utilized an engineered design approach to select and deploy a corporate-wide EHS Management Information System (EHS MIS). The initial objective of the project was to replace an existing outdated Incident Management system with a more robust platform for documenting incidents and improving metrics. Also of high interest was a need to improve Environmental, Health & Safety (HSE) compliance and to reduce operational risk across ten global business regions. A software-neutral third party company was leveraged to objectively facilitate the process. Tasks included gathering corporate and regional requirements, evaluating existing data tracking and reporting systems, understanding and adapting to new Bureau of Safety and Environemental Enforcement SEMS regulations that were promulgated by the Department of the Interior and screening software solutions against the key requirements. Eighteen vendors were assessed against ‘key requirements’ leading to a targeted list of six vendors for inclusion in the request for proposal (RFP) process. The potential companies and their products were further screened with four vendors providing detailed demonstrations of their solutions. The demonstrations provided a clear picture of each software solution and best fit for this company.

The Results

The EHS MIS design planning activities, combined with niche market experience, provided the framework to gain global support internally and select the software solution that could most accurately handle the needs of the organization.

Observations and conclusions

It is important to understand that a successful EHS MIS deployment does not simply involve the implementation of technology, but it is a balance between three cornerstones: People, Process, and Technology. The key elements ensuring success of this global project entailed active corporate and regional stakeholder participation, defining information system processes from a global perspective with flexibility to incorporate unique regional needs, leveraging a platform that streamlines system reporting and distribution of system mainentanance and support activities.

Significance of Subject Matter

As companies seek to quantify and record incidents as well as reducing operational risk, a streamlined approach to HSE performance data collection, handling and reporting activities for global companies becomes key. While global software deployments can become costly, deploying software effectively and efficiently can be accomplished when a well defined engineering methodology is followed
Challenges of Soft Target Security Protection in the Oil and Gas Industry
Authors: Simmerman Jeffry A.
Published: June 2014

Since the 9/11 terrorist attacks, industries and businesses have made significant security improvements in many areas of critical infrastructure protection. This has been especially true of the oil and gas industry. Business continuity and the national security paradigm in which we live have dictated security improvements especially in critical facilities. Coupled with new security regulations mandated by federal and local governments such as the Maritime Transportation Security Act (MTSA) and the Chemical Facility Anti-Terrorism Standards (CFATS), the oil and gas industry has made significant upgrades to security.

As major facilities like refineries, chemical plants and larger offshore production facilities have become hardened, criminals and terrorist organizations have shown a particular trend to avoid hardened targets and attack vulnerable "soft targets" owned by companies. Soft targets are smaller terminals, offshore sites, logistics hubs, pipelines, and office business units or entities that, for a variety of reasons, have not been hardened by significant security upgrades. Many corporations, including major oil and gas providers, own or are affiliated with, numerous business units that have vulnerable employees and property. These business units influence business continuity and are vulnerable as soft targets. This presentation will address:The trending evolution of terrorism toward attacks on softer targets;The factors which influence this trend toward soft targets attacks;The challenges of protecting those soft target assets; andBenchmark security tools that may better prepare a business in protecting potentially softer target business units and assets.
Excellence in Safety Performance Has No Multicultural Barriers: A Case Study
Authors: Daher Elie , Critchley Dave
Published: June 2014

With the expanding global workforce, companies are faced with several barriers to any standardization or centralization plans. Challenges like language difference, local differences, interdependencies, size and maturity and mode of operation can create strong barriers to an effective rollout of a standard or a centralized process.

In 1998, United Safety started operation in Angola with a Canadian workforce. The strategy and intention was to nationalize as fast as possible to sustain a long term presence in the country and to operate effectively. For the first few years, the company had to go through a steep learning curve, getting educated on the differences between the cultures, the challenges of language and the various behaviour safety styles in terms of expectations, tolerance of risk and other safety factors observed by the local workforce.

In addition to the numerous practical challenges, establishment of a HSE culture and practices needs to take into account the culturally different ways of dealing with authority, risks, and individual responsibility, amongst a number of other factors. A lack of cultural competence can in itself lead to miscommunication and misunderstandings, which in turn can cause dangerous situations and accidents.

As the company core business is to provide safety solutions to its customers, it is critical to ensure that the company standards or work practices are persevered and applied irrespective of differences.

Through a rigorous process of recruiting, competency assessment, training, coaching and most importantly cultural understanding and exchange, the company managed to ramp up on their national workforce replacing all expatriate rig personnel in five years and replacing all their coordinators, quality control and office staff including the first General Manager in the next five years.

This case study discusses a successful implementation of standards and centralized processes in Angola to a national workforce, displacing progressively an expatriate community and getting them accepted by the customers. This paper also attempts to share those lessons and discusses failures, consequences and rewards.
Safety Culture Maturity Model: A Process Worth Implementing?
Authors: Daher Elie
Published: June 2014

Safety culture has become a prevalent concern as recent incidents pointed to the lack of safe behavior or attitude. Organizations are struggling to improve their safety culture in a pragmatic way. Maturity is defined as an evolutionary improvement path from an ad hoc, immature process to a mature, disciplined process. It establishes a yardstick against which it is possible to judge, in a repeatable way, the maturity of an organization's planning process and compare it to the state of the practice of the industry.

The maturity model concept was initially developed by the Software Engineering Institute (SEI) as a mechanism to improve the way software is built and maintained. The model provides organisations with a five level process to assist them in developing their software engineering practices. The five levels are Initial, Repeatable, Defined, Managed and Optimising.

The safety culture maturity model was initially developed by Dr Mark Fleming, Chartered Psychologist in 2001. Ten elements were documented:Management commitment and visibilityCommunicationProductivity versus safetyLearning organisationSafety resourcesParticipationShared perceptions about safetyTrustIndustrial relations and job satisfactionTraining

This paper attempts to explore the adequacy of the maturity model to Oil and gas companies and researches the published various implementations to identify the benefits of such maturity model. Some obvious benefits are a provision of known Maturity Level in relation to the safety culture, with recommendations on how to improve and move from one level to another.
One Company’s Site Selection and Screening Process
Authors: Kaal Kimberly J. , Sewell H. James
Published: June 2014

Non-technical risks are generally those above-ground, unforeseen issues that can impact a project’s cost and schedule and are key considerations for Shell’s Appalachia’s exploration and production activities. Examples of non-technical risks include regulatory, environmental, geological, social, political, and community influences or changes that effect industry. The need for a comprehensive process that provides a broad-level identification of sensitive areas and business risks has been addressed by Shell Appalachia, one of Shell’s Upstream Americas assets, through the creation of a unique Site Selection and Screening Process. This process has been customized to specifically fit the needs of Shell Appalachia’s business.

The key concept in Shell Appalachia’s new system and process screening is a spatially-enabled web application providing a visual interface with selective Geographic Information System (GIS) data layers. This web-enabled GIS application acts as a decision support tool to expose and thereby identify risks associated with oil and gas field development while optimizing Shell Appalachia’s voluntary Impact Assessment and iterative planning process. The mapping application displays information in a simple-to-use web GIS where data can be visualized easily and web information kept evergreen. The system plays an integral role in the way activities are planned and managed within a real time decision-making framework, and with this system in place, project planning and permitting can move forward in an efficient manner. The web-enabled GIS application allows planners in all facets of the company to choose from a library of spatial data layers including social (proximity to residences, schools, hospitals), environmental (wetlands, wildlife habitats), regulatory, analytical (air, water, waste), geological, and field data as well as critical infrastructure layers.