bluuebunny/crossref_metadata_2025 huggingface dataset:
HSE Leadership Toolkit: a Valuable Approach to Improve Performances and Reduce Incidents
Authors: Frattini Luca , Scataglini Luciano , Migliore Francesco , Petrone Annamaria
Published: June 2014

This paper presents the toolkit developed by Eni E&P to strengthen the manager’s HSE leadership and commitment.

The first tool is a self assessment form to measure the leadership strength of each manager on the 5 key elements for accident prevention:

- Communication of HSE issues with the workforce. - Reduction of accidents causes. - Promotion of Contractors HSE issues. - Supervision. - Audits and visits.

The self-assessment then guides the user to express his/her personal commitment into visible actions like:

- Site visits. - Participation to HSE Audits. - Periodical meetings/reports/newsletters. - Pre job meetings.

Regular site visits, in particular, help managers understand in depth the company’s activities and where the challenges are, delivering the message that HSE is an essential aspect of everybody’s job and it deserves the highest attention and full commitment.

To help managers get the most from site visits, some checklists have been developed guiding them on the task:

- An "aide memoire" which condenses the key HSE aspects to observe on a site together with some tips on how to reinforce a safe behaviour or how to manage an observed unsafe act. - A pocket-size checklist covering the main aspects of the HSE Management System which, guiding through common management system faults ad typical rule–breaking mechanisms, provides useful indications on the health condition of the site HSE Management System. - A suite of checklists to analyse in detail the compliance to each of the 10 Eni Safety Golden Rules. These checklists are intended to be used with the assistance of an HSE professional and the involvement of the concerned contractor’s representatives.

The leadership and commitment of company managers is essential for the achievement of zero incidents on work activities. This paper aims at disseminating some fundamentals for an effective and visible HSE leadership together with some useful tools which can be deployed to reinforce the HSE leadership and commitment of the managers.
Infectious Disease Outbreak Management: An Effective Tool to Control Outbreaks in an LNG Construction Project in Papua New Guinea
Authors: Nowosiwsky Andry , Diara Malick , Dockins Richard , Burke Nick , Harmen Sonia , Ngunjiri Susan , Brown Amanda
Published: June 2014

IDOM (Infectious Disease Outbreak Management) is a prevention and control approach used by ExxonMobil Corporation for infectious disease outbreak control in remote and offshore settings, The company examined the effectiveness of IDOM in containing varicella outbreaks in a large scale project in Papua New Guinea with a globally mobile labour force.

Application:

Infectious disease outbreaks can have serious health consequences, disrupt operations and affect company productivity. They are of particular concern in remote sites where large-scale outbreaks can exceed project medical team response capabilities as well as those of the local health system. Outbreaks can spread from the worksites to surrounding communities, impact the health of the populations and affect the company’s image and license to operate. IDOM is a public health tool combining sets of easily applicable procedures for outbreak prevention, preparedness and response.

Observations:

From December 2011 to May 2012, four separate outbreaks of varicella virus (chicken pox) were reported in various locations of the Liquified Natural Gas Project. The outbreaks occurred at three large-scale construction camps and one off-shore vessel resulting in 41 cases of chicken pox (approximate total worker population of affected sites 10,000). Earlier adoption of IDOM across project sites allowed quick case detection with timely implementation of mitigation measures that effectively interrupted transmission of the highly infective varicella virus. Several sites reported a single case but no further transmission was observed and no varicella case was reported in any of the surrounding communities.

Significance:

Adoption of IDOM was shown to be very effective for infectious disease outbreak prevention, preparedness and response in large-scale oil and gas construction projects and in preventing transmission to local communities.
The Use of Alternating Flow to Characterize Porous Media Having Storage Pores
Authors: Stewart C.R. , Lubinski A. , Blenkarn K.A.
Published: June 2014

Storage porosity has been considered one of the important pore geometry characteristics of heterogeneousporosity limestones. Storage pores are only containers for fluids, in contrast to flow channel pores which both contain fluids and provide continuity for fluid flow. The concept of another geometry characteristic, "porostriction", is presented as a second pertinent variable in describing limestone pore space. In simple terms, porostriction is a measure of the flow resistance between storage and flow channel pores.

Alternating-flow core-testing theory provides flow relationships which can be used to divide the pore space of heterogeneous-porosity media into flow channel and storage pores and to measure the "porostriction" of the latter. Experimental application of this theory to naturally occurring heterogeneous limestones shows that "porostriction" and the ratio of storage to flow channel pores can be estimated.

Porostriction and porosity ratio are microscopic characteristics which should influence oil-recovery efficiencies during certain types of displacement processes. A knowledge of pore geometry should be valuable in designing or selecting the most effective oil-recovery process for heterogeneous limestones containing storage porosity.

Introduction

The primary and secondary recovery of oil from limestone (carbonate) reservoirs has been and will continue to be a major source of the world's supply of petroleum. Oil recovery from this type of formation is strongly influenced by the size, shape and arrangement of the pore spaces which hold the formation fluids. Therefore, it is expected that better knowledge of pore geometry would lead to design of more effective recovery processes.

The concept of storage and flow channel pores has been presented as an important characteristic of limestone porosity. In this concept, storage pores are only containers for fluids, whereas flow channel pores are those pores which both contain and transmit the fluids. The work reported herein involves the concept of an additional pore characteristic called "porostriction".
Lessons Learned Regarding Offshore Oilfield Applications and Hydraulic Fluids
Authors: McGrath Robert , Davila Sara , Wagner Natalie , Miller Mark
Published: June 2014

As interest and demand increase for reduced liability and exposure related to offshore hydraulic applications, equipment and fluid manufacturers are starting to work together. Over the years, many drilling contractors have learned by trial and error with significant equipment and maintenance costs as a result. One drilling contractor’s goal to reduce the exposure to risk, from purchase to disposal, has led years of experience in the area. As decisions based on a paper review of datasheets can be problematic, understanding the application is vital to ensure performance. As such, there is a need for a better understanding of fluid dynamics and the related tests in a holistic perspective. Specific lessons learned about fluid testing standards and methods, in relation to both performance and environmental parameters, are shared. Topics include case studies on types of environmentally friendly hydraulic (HE) fluids and the associated engineering and compatibility concerns.
An Efficient Reservoir-Simulation Approach To Design and Optimize Unconventional Gas Production
Authors: Yu Wei , Sepehrnoori Kamy
Published: June 2014

Shale-gas production has gained worldwide attention over the past several years. Production from shale-gas reservoirs requires horizontal drilling with multiple hydraulic fracturing to obtain the most economical production. However, there are high cost and uncertainty because of many inestimable and uncertain parameters (e.g., reservoir permeability, porosity, fracture spacing, fracture half length,fracture conductivity, gas desorption, geomechanics, and existing natural fractures). Therefore, the development of a way to quantify uncertainties and optimization of shale-gas production in an efficient and practical method is clearly desirable. In this paper, we present a user-friendly and efficient framework to obtain the optimal gas-production scenario by optimizing the uncertain factors by integrating several commercial simulators, an economic model, design of experiment (DoE), and response-surface methodology (RSM) with a global optimization search engine. Specifically, we use factorial design to screen insignificant factors and find the most influential design and uncertain factors; then, we use RSM to design over those most influential factors to fit a response surface using net present value (NPV) as the objective function; finally, we identify the most economical production scenario under conditions of uncertainty. Eight uncertain parameters [i.e., porosity, permeability, reservoir thickness, reservoir pressure, bottomhole pressure (BHP), fracture spacing, fracture half-length, and fracture conductivity] with a reasonable range on the basis of Barnett-shale information are investigated. Also, different gas prices are considered for the optimization process. This framework is effective and efficient for hydraulic-fracturing- treatment design and production-scheme optimization in unconventional gas reservoirs. It can contribute to providing guidance for engineers to modify the design of a hydraulic-fracture treatment before the actual fracture treatment.
Efficient Displacement of Heavy Oil by Use of Three Hydrocarbon Phases
Authors: Okuno R.. , Xu Z..
Published: June 2014

Mixtures of oil with solvent gas can exhibit three-hydrocarbon-phase behavior at reservoir conditions, where the solvent-rich liquid (L2) phase coexists with the gaseous (V) and oleic (L1) phases. Three-hydrocarbon-phase behavior has been studied in the literature for carbon dioxide (CO2) floods and enriched-gas floods at relatively low temperatures. Prior research on heavy-oil displacement with enriched gas presented that displacement efficiency at a given throughput can be nonmonotonic with respect to gas enrichment. Slimtube experiments for such displacements showed that oil recovery increased first, then decreased, and increased again with increasing gas enrichment. An optimum displacement with a high efficiency of more than 90% was observed when three-hydrocarbon-phase flow was present. However, detailed mechanisms for such an optimum displacement with three phases have not been explained in the literature.

In this research, we investigate mass transfer on multiphase transitions between two and three phases for three-hydrocarbon-phase displacements. Simple conditions are derived for the multiphase transitions that yield high local displacement efficiency by three hydrocarbon phases. The derivation is based on the generalized mass conservation for a multiphase transition in 1D gas injection. The conditions derived are applied to explain nonmonotonic oil recovery in quaternary displacements and the West Sak oil displacements.

Oil recovery at a given throughput can be nonmonotonic with respect to pressure or gas enrichment. Such a nonmonotonic trend can occur when local oil displacement by three hydrocarbon phases becomes more efficient, but slower, with decreasing pressure or decreasing gas enrichment. An optimum pressure or enrichment can occur as a consequence of the balance between the local displacement efficiency and the propagation rate of three hydrocarbon phases. The West Sak oil displacement with enriched gas studied in this research yields a high displacement efficiency of more than 90% at 1.5 hydrocarbon pore volumes (PV) injected at 53% methane (C1) dilution.
A New and Practical Workflow for Large Multipad SAGD Simulation—An Oil-Sands Case Study
Authors: Card Colin C.H. , Kumar Anjani , Close Jason C. , Kjosavik Arnfinn , Agustsson Hafsteinn , Picone Matteo M.
Published: June 2014

Every simulation engineer wishes to simulate large full-field models, but historically reservoir simulation of the steam-assisted-gravity- drainage (SAGD) process has been constrained to single-well models up to a single pad. Models of these sizes provide valuable information and have helped to assess the development potential of reservoirs. These models may be used for reservoir management and to support the decision-making process for the design of the initial completion, operating strategy, and multipad wind-down evaluations, and also qualitatively assess the uncertainty in the SAGD forecast under different geological settings. However, in many cases we are left with the question of how multiwell and multipad communications ultimately affect performance at the well-pair scale. Because of technological constraints with computer hardware and simulation technology, running extremely large multipad models has been until recently largely impractical, especially when trying to run multiple scenarios to better understand the impact of geological and operational uncertainty. In this paper, we present a new and practical workflow that makes running extremely large multipad, multimillion-grid-cell SAGD models a reality. The three major steps of the workflow are (1) generating simulation-friendly geomodels, (2) use of experimental design and 3D submodels on the basis of SAGD performance index (SPI) for numerical tuning, and (3) use of 2D cross sections and SPI to develop dynamic grid-refinement-parameter values for the full 3D model. All of these steps are intended to improve the numerical stability and run time of multipad SAGD simulation models. A 24-SAGD-well-pair model with 2.52 million gridblocks was simulated for 10 years of forecast. The reservoir is geologically complex and highly heterogeneous. We discuss some of the important aspects that need to be accounted for when simulating large-scale SAGD models. Using this new workflow, the simulation run time was reduced from 42 days to 7 days on eight central processing units (CPUs)—a six-time speedup. The resulting run time is short enough to facilitate multirealization simultaneous runs using eight CPUs, hence maximizing the throughput and minimizing the simulation cycle time. This new workflow can be easily replicated and, more importantly, automated to reduce engineering time requirements. While this paper focuses on the SAGD process, this methodology is completely generic in that it can be applied to any large data set for any process. Details will differ depending on the process, but the workflow will be the same.
Understanding the Thermo-Hydromechanical Pressurization in Two-Phase (Steam/Water) Flow and Its Application in Low-Permeability Caprock Formations in Steam-Assisted-Gravity-Drainage Projects
Authors: Ghannadi Sahar , Irani Mazda , Chalaturnyk Rick
Published: June 2014

Steam-assisted gravity drainage (SAGD) is one successful thermal-recovery technique applied in Alberta oil-sand reservoirs. When considering in-situ production from bitumen reservoirs, one must reduce viscosity for the bitumen to flow toward the production well. Steam injection is currently the most promising thermal-recovery method. Although steamflooding has proved to be a commercially viable way to extract bitumen from bitumen reservoirs, caprock integrity and the risk of losing steam containment can be challenging operational problems. Because permeability is low in Albertan thermal-project caprock formations, heating greatly increases the pressure on any water trapped in pores as a result of water thermal expansion. This water also sees a great increase in volume as it flashes to steam, causing a large effective-stress reduction. After this condition is established, pore-pressure increases can lead to caprock shear failure or tensile fracturing, and to subsequent caprock-integrity failure or potential casing failure. It is typically believed that low-permeability caprocks impede the transmission of pore pressure from reservoirs, making them more resistant to shear failure (Collins 2005, 2007). In considering the “thermo-hydromechanical pressurization” physics, low-permeability caprocks are not always more resistant. As the steam chamber rises into the caprock, the heated pore fluids may flash to steam. Consequently, there is a vapor region between the steam-chamber interface penetrated into the caprock and the water region within the caprock which is still at a subcritical state.

This study develops equations for fluid-mass and thermal-energy conservation, evaluating the thermo-hydromechanical pressurization in low-permeability caprocks and the flow of steam and water after steam starts to be injected as part of the SAGD process. Calculations are made for both short-term and long-term responses, and evaluated thermal pressurization is compared for caprocks with different stiffness states and with different permeabilities. One can conclude that the stiffer and less permeable the caprock, the greater the thermo-hydromechanical pressurization; and that the application of SAGD can lead to high pore pressure and potentially to caprock shear, and to subsequent steam release to the surface or potential casing failure.
Application of Analytical Proxy Models in Reservoir Estimation for SAGD Process: UTF-Project Case Study
Authors: Azad Ali , Chalaturnyk Richard
Published: June 2014

Steam-assisted gravity drainage (SAGD) has been used successfully for the last 25 years in Canada. SAGD is a thermal recovery process that was invented to extract highly viscous bitumen from deep Canadian oil-sands reservoirs. To date, the original idea of SAGD has not changed greatly since the first pilot test in 1987. However, field operation and reservoir management have been influenced by recent developments in technology. Advanced drilling techniques, automated production control, and real-time data monitoring are gradually transforming the SAGD process into smart fields. As such, improving current history-matching techniques would support fast decision-making requirements significantly in closed-loop reservoir management. This paper recommends analytical solutions for simulations with medium-to-high levels of uncertainty. This shows how an analytical simulator can be improved effectively to mimic the essential features of a SAGD field for fast history matching. Combined with the analytical model recently proposed by the authors, this paper investigates the methodology to apply uncomplicated analytical/mathematical solutions to practical cases. The two underground test-facility (UTF) pilot-test case studies covered in this paper provide a better understanding of the proposed methodology. History matching results show that the current analytical models are suitable to act as proxy models for optimization purposes.
Barnett Shale Production Outlook
Authors: Browning John , Ikonnikova Svetlana , Gülen Gürcan , Tinker Scott W.
Published: June 2014

We developed a production-outlook model on the basis of an interdisciplinary analysis of production data from more than 15,000 wells and geologic data on the Barnett play. The model is the most granular to date because it incorporates 10 tiers of varying productivity and well economics of average wells by tier; it covers close to 8,000 square-mile blocks across partly drained and undrilled acreage, divided between low-Btu and high-Btu segments, and uses drillwell potential by tier for the total area; and it is unique in its use of production profiles on the basis of transient linear drainage. Drilling pace is adjusted to changes in natural-gas price relative to well economics, historical attrition rates, and logistical constraints. We analyze scenarios and conduct a simulation analysis on the basis of reasonable ranges for natural-gas price, remaining acreage developable in partly drained and undrilled blocks, improvement in technology and well cost performance, and economic limit for shutting in a well. The Barnett is the most exploited shale play in the world; cumulative production to 2012 is 13 Tcf. Our analysis indicates remaining recovery of approximately 2.5 times of cumulative production in the base case, but this is subject to many uncertainties. Base case results are consistent with actual production in 2011 and 2012.
Advance Study of Top of Line Corrosion Risk: Methodology and Evaluation of Mitigation for New Pipeline
Authors: Santhyani Desy
Published: June 2014

Top of line corrosion (TLC) is experienced on the upper section of gas or multiphase pipelines operated in a stratified flow regime. TLC occurs when water vapor, contained in the gas phase, condenseson the internal upper pipe wall. The condensation may be caused by the cold wall effect generated by external cooling sources (river water, sea water or cold air) when the pipe is not properly heat insulated or buried. Both dissolved CO2 and possible presence of organic acids reduce the pH of condensedwater and enhance corrosiveness. Instantaneous high corrosion rates, up to 10 mm/y, can occur in the first production period, although worst corrosion rates averaged over a longer period of 2-3 years are rather in the range of 1 to 3 mm/y. In addition, as long as the flow regime is stratified, usual corrosion inhibitors cannot reach the upper surface of the pipeline.

This study covers TLC assessment on new 8 km pipeline that will transport multiphase hydrocarbon from a new platform to existing facilities. Expected production life of the field is quite short, less than 10 years, maximum wellhead flowing temperature is 105℃ and CO2 content is about 8%. Based on TLC assessment performed during conceptual study, TLC has been considered as a significant issue in case of water condensation rate (WCR) > 0.05 gr/m2s. Being WCR far above such limit, the use of cladding pipe was proposed as the main mitigation measure to limit TLC consequences. However during the next stage of Project, TLC risk was re-assessed in more detail by using more accurate data in order to find the best solution in term of CAPEX and OPEX.

Following studies were performed: Water condensation rate studyWCR study is performed in order to identify the pipeline length where TLC will be occured and how long TLC risks will last. Such calculation is done by using OLGA software based on the data of wellhead flowing temperature (WHFT).Top of line corrosion rate studyTLC rate is calculated to assess the feasibility of the mitigation that consists in having a sufficient corrosion allowance to cover TLC risk and to evaluate the required corrosion allowanceSensitivity study of using thermal insulation and buried pipe

Performed to assess whether the used of thermal insulation and buried pipe can be an option to mitigate TLC

Result of these studies demonstrated that the utilization of carbon steel with extra corrosion allowance, combined with cold spot prevention as the best technical-economic option for TLC mitigation. It was also possible to conclude that thermal insulation or bury the pipe may not always be the most appropriate option due to the quality assurance along the years, the constructability constraint and the cost.
Geomodel Geometry Distorted by Seismic Velocity Uncertainties
Authors: Piquet G. , Pivot F. , Forge A.
Published: June 2014

Structure of the geomodel is always controlled by key depth horizons and faults coming from seismic interpretation. However, these geophysical surfaces carry uncertainties attached to seismic picking and seismic velocities. Some error done on estimation of such velocities can have a great impact on final volumes & on field development as it can change drastically the shape of the reservoirs.

We propose here a multi-realizations approach to manage properly these uncertainties during the geomodeling process, in order to estimate their impact and build alternative distorted geomodels for pessimistic and optimistic scenarios.

This method relies on the alternative velocity models built by the interpreters to depth convert the horizons at the origin of the geomodel grid. These velocity models reflect geophysical uncertainty through alternative hypothesis to the basecase velocity model. The stochastic approach presented mixes those models generating hundreds of intermediate scenarios for top & base reservoir horizons. For instance structure can be tilted, smaller or larger compared to the basecase.

This approach enables the user to decide how far from the basecase top & base reservoir realizations should vary (using confidence weights). So the user can maintain the possible realizations around the most likely one (??).

We propose here to expose & apply each step of this technique to an offshore West-Africa field. The objective of the study is triple: to get a dispersion of the possible GRV values, to get distorted versions of the geomodel according to optimistic or pessimistic GRV realizations so that extreme cases can be analyzed. And eventually to assess possible variations of the flanks of the structure.

This last point is crucial to take into account uncertainties in the producer/injector well development pattern.
Effects of Segmentation and Skeletonisation Algorithms on Pore Networks and Predicted Multiphase Transport Properties on Reservoir Rock Samples
Authors: Idowu N. A. , Nardi C.. , Long H.. , Varslot T.. , Øren P. E.
Published: June 2014

Networks of large pores connected by narrower throats (pore networks) are essential inputs into network models which are routinely used to predict transport properties from digital rock images. Extracting pore networks from micro-computed tomography (micro-CT) images of rocks involves a number of steps: filtering, segmentation, skeletonisation etc. Because of the amount of clay and their distribution, segmentation of micro-CT images is not trivial and different algorithms exist for doing this. Similarly, several methods are available for skeletonising the segmented images and for extracting the pore networks. The non-uniqueness of these processes raises questions about the predictive power of network models. In the present work, we evaluate the effects of these processes on the computed petrophysical and multiphase flow properties of reservoir rock samples.

Using micro-CT images of reservoir sandstones, we first apply three different segmentation algorithms and assess the impacts of the different algorithms on estimated porosity, amount of clay and their distribution. Single-phase properties are computed directly on the segmented images and compared with experimental data. Next, we extract skeletons from the segmented images using three different algorithms. On the generated pore networks, we simulate two-phase oil/water and three-phase gas/oil/water displacements using a quasi-static pore network model.

Analysis of the segmentation results show differences in the amount of clay, total porosity and computed single-phase properties. Simulated results show that there are differences in the network-predicted single-phase properties as well. However, predicted multiphase transport properties from the different networks are in good agreement. This indicates that the topology of the pore space is well preserved in the extracted skeleton. Comparison of the computed capillary pressure and relative permeability curves for all networks with available experimental data show good agreements.

By using a segmentation which captures porosity and microporosity, we show that the extracted networks can be used to reliably predict multiphase transport properties irrespective of the algorithms used.
Self-Adapting Bottom-Hole-Assembly Vibration Suppression
Authors: Hutchinson Mark , Burgess Dan , Thompson Fred , Kopfstein Allen
Published: June 2014

The state-of-the-art approach to downhole shock and vibration mitigation is to insert into the bottom-hole-assembly (BHA) a shock-sub or torque-limiter with response characteristics pre-configured prior to tripping into the borehole and then continuously monitor downhole vibrations with the driller making adjustments to surface control parameters whenever the downhole shock levels are excessive. Some top-drive control systems are also capable of mitigating the torsional stick-slip dysfunction. A novel approach is to use downhole shock and vibration measurements to actively adjust the damping characteristics of a downhole shock-absorber, thereby changing the axial (and optionally torsional) stiffness of the BHA itself, in response to transient downhole dysfunctions and without the inherent delay of transmitting data from downhole to the driller at the surface.

At the heart of this new adaptive shock-absorber is a magneto-rheological damping fluid whose viscosity is modified whenever excessive downhole vibrations are detected by adjusting the electro-magnetic field through which the damping fluid passes. This is similar technology to that used for protecting buildings during earthquakes and in high performance vehicles that have intelligent shock-absorbers that let the driver select a preferred stiffness for the vehicle's suspension.

This paper describes this innovative downhole self-adapting vibration damper and its autonomous control system that detects drilling dysfunctions and then iteratively adjusts the device's damping characteristics until the destructive downhole forces and motions are mitigated – potentially before the driller at the surface is even aware that there was a problem. Modeling of the magneto-rheological fluid response is presented together with some initial downhole test results demonstrating the tool's ability to control the stiffness and vibration characteristics of a bottom-hole-assembly. Comparisons of downhole shock levels and the amplitude of various types of vibrations at different frequencies illustrate how the self-adapting damper can suppress different modes of BHA dysfunction and thus also demonstrating the device's ability to extend bit life and drilling tool life and to improve overall drilling performance.

Automatically controlling drilling dysfunctions from within the BHA at their source is timelier and potentially more effective than the current approach of telemetering downhole vibration information to the driller at the surface after the bit and drill string components have already been damaged over some incremental time period. The more instantaneous response of a self-adapting tool has the ability to prevent drilling tool failures, reduce bit wear, sustain higher penetration rates with a sharper bit and extend the interval drilled during a single bit run. For certain drilling applications this can significantly reduce the number of bit runs per hole section as well as the related drilling time and cost.
Ceramic Screens - An Innovative Downhole Sand Control Solution for Old & Challenging Cased Hole Completions
Authors: Nadeem Asaf , Strazzi Alfonso , Justiniano Pablo , Lopez Mario , Wildhack Stefanie , Joly Samuel
Published: June 2014

Erosion in gas wells caused by sand producing formations can result in severe operational issues leading to the degradation of surface and downhole equipment and the shutdown of production facilities at surface.

Old cased hole wells in highly unconsolidated, poorly sorted sandstone formations require robust sand control. In such instances, conventional gravel packing methods are not always possible and the installation and maintenance of downhole sand control throughout the well life can be challenging. In gas wells where sand velocities are high, the supporting metallic material being used in, for example standalone sand control screens is subject to plugging and subsequent rapid wear because of its low resistance to erosion. Hence the longevity of metallic sand control equipment is poor and frequent expensive re-completions and workovers are required.

An innovative solution using ceramic screens was used in an existing gas well in Bolivia, South America. The well geometry included double casing with sub-optimal cement across the target zone and, due to the complexity of voids behind the casing, it was not possible to perform the initial option of a cased-hole gravel pack. In addition to sand control the completion required mechanical zonal isolation to prevent water ingress at a later stage. In summary the project involved removing the existing completion, isolating deeper lying depleted producing zones, clearing the casing of debris, re-perforating the casing, installing a new completion with ceramic screens and zonal isolation valves.

BG Group in conjunction with German ceramics manufacturer ESK developed over a period of 18 months a series of ceramic sand control screens and sliding sleeve protections that provided a downhole sand control completion solution complete with mechanical water isolation.

The successful project exceeded all expectations and to date the well has produced sand free. The operational time and re-completion costs were less than of a cased-hole gravel pack, the operation much simpler and safer.

BG are now working on a project to use this innovative technology as a thru-tubing sand control solution for existing high rate gas wells offshore worldwide where open hole or cased hole gravel packs have failed.
Using Dynamic Simulation to Assess Effectiveness of Downhole Pump for Gas Well Deliquification
Authors: Yusuf Rahel , Veeken Kees , Hu Bin
Published: June 2014

Reservoir pressure depletion in gas reservoirs causes gas flow reduction with time and eventually leads to liquid loading as the gas flow up the well can no longer efficiently lift the associated liquids to surface. Liquid loading has a detrimental impact on production and a suitable deliquification method is required to continue production and maximize recovery. A downhole pump is one such deliquification measure where the pump sits at the bottom of the producing interval and evacuates the accumulated liquids up an insert (coiled tubing) string. It is important to assess beforehand whether the pump will effectively remove the liquids and hence deliver sufficient business value.

A transient multiphase simulator has been used to simulate the gas well liquid loading process in a candidate well completed with 5.5" tubing, followed by the deliquification process triggered by a downhole pump installed 20 m above the bottom of the producing interval on a 1.5" coiled tubing. Simulations have been conducted for seven different liquid pump rates, three reservoir pressures and two water-to-gas ratios to assess the effectiveness of the pump under different operating conditions and to arrive at the optimum pump size and operation methodology.

Simulations indicate that the downhole pump is capable of deliquifying the well and restoring production. However, for a given pump capacity and reservoir pressure, the surface gas production may either oscillate or settle at a steady state value. Oscillations occur when the pump capacity is too high and causes gas ingress into the pump, which introduces partial albeit temporary liquid loading of the wellbore. Continuous steady state gas production occurs when the pump capacity is not too high and an equilibrium situation is reached between the liquid being pumped out and the liquid being produced. The optimum pump rate is controlled by the effectiveness of the downhole separation between the gas and liquid phases and will minimize oscillating ingress of gas into the pump.

This study emphasizes the role of transient simulations in predicting the effectiveness of a deliquification measure before embarking on field deployment. The simulations provide valuable insight into flow and pressure transients inside the wellbore during a gas well deliquification using a downhole pump. The information retrieved from the transient simulations is used to decide the optimum pump capacity and operation guidelines. To the best of authors' knowledge, this is the first time that a transient simulation of a downhole pump for gas well deliquification is presented in open literature.
Foam Cement Job Simulations: Learning from Field Measurements
Authors: Dooply Mohammed , Flamant Nicolas , Kanahuati Alia Iza , Pringuey Thibault
Published: June 2014

Foamed cement is often used to seal the annulus of many surface casing strings in deepwater offshore wells. The objective of this paper is to highlight the benefits a foamed fluid placement simulator brings to the design and evaluation processes for foam cement jobs.

A dynamic compressible hydraulic model that simulates the flow of nitrified fluids during primary cementing operations is presented. For a long time, the industry had relied on models that used average density properties for the foamed fluid. Yet the foam quality can change from 70% at surface conditions to 10% or less at bottomhole conditions. In terms of density this ranges from 600 kg/m3 (5 lb/gal) to 1800 kg/m3 (15 lb/gal). The average density approximation is therefore too coarse. In reality, there is continuous changing of fluid density and rheology during placement of the foamed fluids due to the changes of pressure and temperature along the flow path. Both density and rheology variations can be taken into account in a compressible hydraulic model that simulates the flow of nitrified fluids during primary cementing operations.

Measurements taken on actual foam cement jobs are compared to the simulator's output. The actual data and the simulated output compare favorably. Discrepancies between the model and acquired data are also analyzed to improve the understanding of the actual operation. The inherent limitations of post job analysis are discussed. The absence of caliper or known geometry on surface and conductor casings becomes more obvious. The placement of sensors on flow lines, the absence of sensors after the foam cross, and the uncertainty on geothermal gradient are also sources of divergence between the model and the measurements as will be seen through case study in this paper.

The continuous improvement of the model and the simulator will contribute to more robust foam cement job designs. Robust foam cement job designs will assure the isolation integrity of the structural casing strings for deepwater wells and ensure safe operations while executing this type of jobs.
High-Pressure Data and Modeling Results for Phase Behavior and Asphaltene Onsets of Gulf of Mexico Oil Mixed With Nitrogen
Authors: Hustad Odd Steve , Jia Na , Pedersen Karen Schou , Memon Afzal , Leekumjorn Sukit
Published: June 2014

This paper presents fluid composition, high-pressure pressure/volume/temperature (PVT) measurements, and equation-of-state (EoS) modeling results for a recombined Tahiti oil, Gulf of Mexico (GoM), and for the oil mixed with nitrogen in various concentrations. The data include:

Upper and lower asphaltene onset pressures and bubblepoint pressures for the reservoir fluid swelled with nitrogen. At the reservoir conditions of 94 MPa (13,634 psia) and 94°C (201.2°F), asphaltene precipitation is seen after the addition of 27 mol% of nitrogen. Viscosity data for the swelled fluids showing that the addition of nitrogen significantly reduces the oil viscosity. Slimtube runs indicating that the minimum miscibility pressure (MMP) of the oil with nitrogen is significantly higher than estimated from published correlations.

The data were modeled with the volume-corrected Soave-Redlich-Kwong (SRK) EoS and the perturbed-chain statistical association fluid theory (PC-SAFT) EoS. Although both equations provide a good match of the PVT properties of the reservoir fluid, PC-SAFT is superior to the SRK EoS for simulating the upper asphaltene onset pressures and the liquid-phase compressibility of the reservoir fluid swelled with nitrogen.

Nitrogen-gas flooding is expected to have a positive impact on oil recovery because of its favorable oil-viscosity-reduction and phase behavior effects.
Managing Shut-in Time to Enhance Gas Flow Rate in Hydraulic Fractured Shale Reservoirs: a Simulation Study
Authors: Fakcharoenphol Perapon , Torcuk Mehmet , Bertoncello Antoine , Kazemi Hossein , Wu Yu-Shu , Wallace Jon , Honarpour Matt
Published: June 2014

Some shale gas and oil wells undergo month-long shut-in times after multi-stage hydraulic fracturing well stimulation. Field data indicate that in some wells, such shut-in episodes surprisingly increase the gas and oil flow rate. In this paper, we report a numerical simulation study that supports such observations and provides a potentially viable underlying imbibition and drainage mechanism. In the simulation, the shale reservoir is represented by a triple-porosity fracture-matrix model, where the fracture forms a continuum of interconnected network created during the well simulation while the organic and non-organic matrices are embedded in the fracture continuum. The effect of matrix wettability, capillary pressure, relative permeability, and osmotic pressure, that is, chemical potential characteristics are included in the model.

The simulation results indicate that the early lower flow rates are the result of obstructed fracture network due to high water saturation. This means that the injected fracturing fluid fills such fractures and blocks early gas or oil flow. Allowing time for the gravity drainage and imbibition of injected fluid in the fracture-matrix network is the key to improving the hydrocarbon flow rate during the shut-in period.
Factors Affecting Early Well Productivity in Six Shale Plays
Authors: Crafton James W. , Noe Sandra L.
Published: June 2014

A population of over 360 wells from six shale play areas was investigated to assess the impact of various early production management strategies, with attention given to the time delay between stimulation and first production, the "resting" or "soak" period, the effect of subsequent shut-ins, proppant conductivity and interfacial tension management. Subsets of this population were used to perform the various evaluations. The use of the non-volatile or persistent interfacial tension management chemistry significantly mitigated, but did not prevent, damage arising from delay to first production or shut-ins. Based on the performance metric used, delay to first production is not beneficial. However, based on other data, the likelihood of improvement when using persistent interfacial tension management is slightly better than even odds, but without it, only about one in three. Once on production, if the rate with which the flowing pressure was decreased exceeded about 100 psi per day, a significant negative impact on the reservoir / wellbore connectivity was observed. The last control factor was the obvious benefit derived from using high conductivity proppants, in conjunction with the persistent interfacial tension management.
A Day in the Life of a Barrel of Water: Evaluating Total Life Cycle Cost of Hydraulic Fracturing Fluids
Authors: Watts Robin
Published: June 2014

For several years now, regulatory agencies including the U.S. Environmental Protection Agency (EPA), energy associations like the American Petroleum Institute (API), and more recently the Center for Sustainable Shale Development (CSSD) have provided recommendations, regulations, performance standards, and guidelines to improve water management in oil and gas exploration. Yet, to fully appreciate the life cycle costs of fluids used for hydraulic fracturing – including water, one needs to examine the total costs of fluid acquisition, management and disposal. Typically, these costs are divided between various groups within an operator's organization (i.e., completions and production), with budgeting emphasis on acquisition costs during the completions process.

This paper examines the total life cycle costs of hydraulic fracturing fluids, comparing water-based and energized solutions. It evaluates when fracturing fluids energized with carbon dioxide (CO2) or nitrogen (N2) can be used to reduce water volume for more economical hydraulic fracturing. It also evaluates how the selected fracturing fluid can affect productivity. In certain situations, the increased productivity achieved with energized solutions can more than offset lower per-barrel water costs, driving a lower overall unit cost of production. To approach our analysis, we will look at "A Day in the Life of a Barrel of Water" used for hydraulic fracturing.
Design of a Cyclonic Solids Jetting Device and Slurry Transport System for Production Systems
Authors: Rawlins C. Hank
Published: June 2014

Production separators require increased sand handling capability as watercut grows due to field maturation and EOR use. A compact cyclonic jetting device allows on-line fluidization and removal of sand and solids from production vessels and tanks. The cyclonic transporter combines the jetting and evacuation functions into a single device for integration into new build or retrofit separation vessels. Using an optimized hydrocyclonic platform this technology converts jetting spray water into shielded vortex flow that affects sand in a circular zone with no disturbance of the oil-water interface. The area of influence for the device is a function of set height, spray flow, and spacing. The optimum placement of a single unit was determined at 10 cm (4") set height with 0.7 barg (10 psig) spray pressure. At 28 cm (11") sand bed depth in an atmospheric tank, the device has a circular area of influence of 1.1 m² (11.7 ft²).

Placing two units in parallel with overlap of their affected zones does reduce the egg-carton effect. Optimum operation, in terms of total sand removed, occurs when the units do not overlap. The discharge slurry concentration has a peak of up to 60 wt.% solids which follows an exponential decay profile as the sand is evacuated. The concentration decreases to negligible sand at 10-15 minutes of operation which validates the process jetting time. The design of the cyclonic jetting device allows on-line solids removal using less water than conventional spray jetting with no disturbance of the oil-water interface during operation and elimination of mechanical wear.
Visualization and Analysis of Surfactant Imbibition into Oil-Wet Fractured Cores
Authors: Mirzaei Mohammad , DiCarlo David A. , Pope Gary A.
Published: June 2014

Imbibition of surfactant solution into the oil-wet matrix in fractured reservoirs is a compl icated process which involves gravity, capillary, viscous, and diffusive forces. The standard experiments for testing imbibition of surfactant solution involve an imbibition cell, where the core is placed in the surfactant solution and the recovery is measured versus time. Although these experiments prove the effectiveness of surfactants, little insight into the physics of the problem is achieved.

In this study, we performed water and surfactant flooding into oil-wet fractured cores and monitored the imbibition of the surfactant solution using CT scanning. From the CT images, the surfactant imbibition dynamics as a function of height along the core was obtained. While the water flood only displaced oil from the fracture, the surfactant solution imbibed into the matrix; the imbibition is frontal with the greatest imbibition rate at the bottom of the core, and the imbibition decreasing roughly linearly with height. Experiments with cores of different sizes showed that increase in either the height or the diameter of the core causes decrease in imbibition and fractional oil recovery rate. We also perform numerical simulations to model the observed imbibition.

Based on the experimental measurements and numerical simulation results, we propose a new scaling group that includes both the diameter and the height of the core. We show that the new scaling groups scale the recovery curves better than the traditional scaling group.