bluuebunny/crossref_metadata_2025 huggingface dataset:
A Coreflood Investigation of Nanofluid Enhanced Oil Recovery in Low-Medium Permeability Berea Sandstone
Authors: Hendraningrat Luky , Li Shidong , Torsæter Ole
Published: June 2014

Nanoparticles have become an attractive agent for improved and enhanced oil recovery (IOR & EOR) at laboratory scale recently. Most researchers have observed promising result and increased ultimate oil recovery by injecting nanofluids in laboratory experiments. In previous study, we observed that interfacial tensions (IFT) decreased when hydrophilic nanoparticles were introduced to brine. The IFT decreases as nanofluids concentration increase and this indicates a potential for EOR. We have also investigated nanofluid flow in glass micromodel and high permeability Berea sandstone (ss) cores, and we observed that the higher concentration of nanofluids; the more impairment of porosity and permeability. Since low permeability oil reservoirs have still huge volume of oil reserves, this study aims to reveal nanofluids possibility for EOR in low-medium permeability reservoir rocks and investigate its suitable concentration.

In this paper, laboratory coreflood experiments were performed in water-wet Berea ss core plugs with permeability in range 9- 35 mD using different concentrations of nanofluids. Three nanofluids concentrations were synthesized with synthetic brine; 0.01, 0.05 and 0.1 wt.%. To investigate disjoining pressure as displacement mechanism due to nanoparticles, contact angle between crude oil from a field in the North Sea and brine/nanofluids have been measured. Increasing hydrophilic nanoparticles will decrease contact angle of aqueous phase and increase water-wetness.

Despite increasing nanofluid concentration shows decreasing IFT and altering wettability, our results indicate that additional recovery is not guaranteed. The processes and results are outlined and also further detailed in the paper to reveal the possible application of nanofluid EOR in lower-medium permeability oil reservoir.
The Development and Field Application of New Surfactant Chemistries for Application to Heavy Oils
Authors: Temple-Heald Clare , Davies Craig , Wilson Natalie , Readman Nicola
Published: June 2014

A critical part of any Oilfield production processing is oil and water separation and although this area has had highly efficacious demulsifier products developed for a number of production scenarios the application to "heavy" oils remains problematic.

Over 70% of the future recoverable reserves have been designated as heavy oil and these developments will pose a number of unique oil and water separation challenges in production, transportation and refining compared to lighter crudes. Demulsification and desalting of these challenging crudes is needed in a wide variety of secondary and tertiary enhanced oil recovery applications and techniques, including waterflooding, steam assisted gravity drainage and cyclic steam stimulation.

This paper describes the laboratory development and subsequent field-testing of a specific range of chemistry for application to broad spectrum of heavy oil scenarios. It was found that specific properties related to interfacial tension were important, and this will be elaborated further. From the data, a model situation using specifically selected heavy oils has been developed for the evaluation of a number of surfactant chemistries, the criteria also includes a structure versus performance relationship to identify optimum surfactant properties.

This work has resulted in a tailored range of demulsifiers, which will add to the relatively small number of chemistries able to effectively be applied across the growing heavy oil development and production area. In addition to technical efficacy recognition of environmental impact and some specific chemistry relating to application in environmental regulated areas such as the North Sea will be discussed.
Recent Advances in Organically Crosslinked Conformance Polymer Systems
Authors: Reddy B. R. , Eoff Larry , Crespo Freddy , Lewis Chris
Published: June 2014

Organically crosslinked polymer systems have experienced considerable commercial success in shutting off undesirable water production. One of the systems most widely used to date employs acrylamide-containing polymers as base polymers and polyamines as crosslinkers. Its success can be attributed to 1) low viscosity in a noncrosslinked state, 2) versatility and stability over a wide temperature range, 3) rigid ("ringing") gel formation, and 4) deep matrix penetration.

The objective of the present study was to improve the current acrylamide- and amine-based polymer formulations by significantly reducing the polymer concentrations while retaining the gel performance. This was accomplished by the inclusion of organic activators that substantially increase the crosslinking reactivity of the polyamine, allowing reduction in the polymer loading necessary to achieve desired gel times at a specific temperature. The activator materials included alkanolamines and quaternary ammonium salts. An increase in base polymer molecular weight also allowed for significant reduction in base polymer concentrations (to ≤ 1%). While this results in a lower cost system, and is more environmentally acceptable, the change in the quality of the gel from a stiff to a highly deformable type can result in the decreased ability of the gel to resist pressure. Bimodal molecular weight distribution is presented as an alternative approach to decrease polymer loading. This technique consists of the addition of variable amounts of high-molecular-weight base polymer to a constant concentration of low-molecular-weight base polymer.

The newly developed formulations, in some cases, allowed for a reduction of up to 40% of base polymer concentration. Results from gel time measurements over a wide temperature range using different base polymers, crosslinker polymers, and potential activation mechanism(s) are discussed.
Mechanical and Thermal Stability of Polyacrylamide-based Microgel Products for EOR
Authors: Dupuis G. , Al-Maamari R. S. , Al-Hashmi A. R. , Al-Sharji H. H. , Zaitoun A.
Published: June 2014

In a previous work (Zaitoun, et al., 2012), a study of the shear stability of different EOR polymers was reported. Shear stability was found to directly correlate to chain flexibility. Thus, for a flexible coil such as polyacrylamide, the presence of large monomer groups (e.g. ATBS, NVP) leads to an increase of its rigidity, hence enhancing its shear stability. However, these polymers remain highly shear sensitive in comparison to the rodlike Xanthan gum.

In this paper shear and thermal stability studies of different microgels are reported. Microgels are micrometric hydrophilic gel particles composed of partially cross-linked polyacrylamide-based chains. These microgels are already used for water shut-off treatments and conformance control. Because of their stability, they could be used in the future as sweep improvers EOR chemicals.

Comparative tests were performed with microgels and three different polyacrylamide-based EOR polymers in terms of shear and thermal stability. The impact of the internal cross-linking density, the size and the conditioning on microgels mechanical stability was investigated. For each microgel, solutions were prepared at different salinities and aged in ovens at 80, 105 and 140°C over one month in oxygen-free conditions to check their thermal stability.

Results showed that microgels maintain their integrity over a wide range of shear rate (up to 1.2x106 s−1) behaving like the rodlike Xanthan gum, whereas classical polyacrylamide-based polymers loose more than 50% of their initial viscosity at shear rate as low as 104 to 105 s−1. No difference in behavior is observed for the product prepared in powder or in emulsion form. Finally, at the highest temperature investigated (i.e. 140°C), thermal degradation is minimal for the microgels with low cross-linking densities and no thermal degradation has been observed for the microgels with the highest cross-linking densities.

The exceptional mechanical and thermal stability of the polyacrylamide-based microgels and their easiness to be tailored for the required application make these chemicals excellent candidates as future sweep improvers under harsh reservoir conditions in which other conventional polymers might fail.
An Experimental Study on Chemical Flooding Using In-Situ Precipitation Inhibitor
Authors: Elraies Khaled A. , Alta’ee Ali F. , Ibrahim Ahmed A. , Saaid Ismail M.
Published: June 2014

This paper introduces a new in-situ precipitation inhibitor that improves the performance of the conventional ASP flooding. This inhibitor is generated to overcome the precipitation problems prevalent with ASP flooding using brines containing high total dissolved solids. The generated precipitation inhibitor (sodium acrylate) was tested in a chemical formulation containing Alpha Olefin Sulfonate as a surfactant and sodium carbonate as an alkaline. A fluid-fluid compatibility tests were conducted to examine the performance of the precipitation inhibitor using hard brine having large quantity of divalent metal cations. The effect of the precipitation inhibitor on interfacial tension and surfactant adsorption were investigated using various inhibitor concentrations. The in-situ precipitation inhibitor showed an excellent performance in preventing calcium and magnesium precipitations, and solutions remained clear for 45 days at 80 °C. The interfacial tension was reduced significantly when the inhibitor was present in the system. As the sodium acrylate concentration is increased to an optimal value, an ultralow interfacial tension of 0.04 mN/m could be achieved. The advantage of the in-situ inhibitor is the use of hard brines without the need for softening the injection water. This could reduce the cost of chemical EOR process and makes it more suitable for environmentally sensitive applications, particularly offshore application.
Development Field Having Dolerite is Extra Challenging
Authors: Widjiastono Agus , Belzuz Fernando Pérez , Vicente Mario Gustavo
Published: June 2014

The effectiveness and efficiency on developing the field are influenced by the development drilling cost and reservoir production rate performance. The cost of drilling is reliant to the reservoir objective depth and the obstacle anomaly features encountered prior to reach the reservoirs. The more and difficult obstacles faced will cost more on drilling operation.

Dolerite is a hard rock originated from volcanic rock deep beneath basement. When dolerite is present at shallower depths than the main reservoir, it will become one of the obstacles due to its hardness that can cause the slow drilling rate. The fact that the character of the distribution and thickness of dolerites is pattern less, make it more challenging on the drilling design and plan.

The geological condition of the Kahlouche field area has brought to the situation of the presence of dolerite in the shallower sedimentary layers of upper Devonian, Carboniferous and lower Cretaceous. Dolerite intruded vertically and laterally into the sedimentary layers in the form of dyke and sills in variety range of thickness and areas of distribution.

Better understanding of dolerite thickness and distributions are additional challenging work of development subsurface team, but it is necessary to provide proper input for development well prognosis, design and plan. These dykes and sills framework existing above the reservoir zones make the well development placing become challenging, mostly in the situation where a good location for reservoir target is often coincident with the complex dolerite configuration. This paper shares the issues caused by dolerites and the working plan and progress to better understand and well prepare for effective and efficient development phase activities.
Seismic Reservoir Monitoring of a Thermal EOR Redevelopment; Thick Heavy oil Field in Oman
Authors: Al Adawi Rashid , Rocco Guillermo , Al Busaidi Said , Al Maamari Abdullah , Al Ghafri Salah , Kiyashchenko Denis , Lopez Jorge , Berlang Wilfred , Zwaan Marcel
Published: June 2014

Petroleum Development Oman (PDO) is currently redeveloping a thick deep heavy oil reservoir using steam flooding. Steam has been injected in the first inverted 7-spot pattern (1P) since late 2008. An areal surveillance plan was created together with Shell International EP (SIEP) to test different monitoring techniques in order to select the most cost-efficient one for full field deployment. Ideally, the selected method would improve understanding of the thermal recovery concept and optimise further pattern development. The plan included three crosswell seismic profiles, 3DVSP and surface seismic, all in time-lapse mode. The 2006 surface seismic was used as the baseline for the surface seismic acquired in 2012. The data shows very good repeatability. However as the project construction phase took place after 2006, the 4D surface seismic was influenced by the 4D noise caused by surface changes. Detecting 4D signals is challenging particularly with the relatively small amount of injected steam. In contrast, crosswell seismic data and the 3DVSP were acquired after the construction work took place. The crosswell seismic 4D velocity profiles showed changes below and above top of reservoir, which led to the consideration of geomechanical effects. The 3DVSP data indicated reservoir changes towards the north of the injector which is in line with the temperature surveys, also indicating preferential changes towards the north. These encouraging results led to a second monitor 3DVSP acquisition followed by a pilot 3DVSP using a fibre-optic cable installed in the well for distributed acoustic sensing (DAS). The second monitor 3DVSP shows that previous 4D signals have moved further towards the north. It also indicates additional changes at the bottom perforation zone (as injection was shifted to bottom) with a preferential movement towards the north as well. Furthermore DAS VSP was found comparable enough with the conventional VSP and therefore it can detect reservoir changes. A plan is being worked to fit the existing observation wells with DAS cables and acquire a major 3DVSP baseline. The DAS cable will be combined with distributed temperature sensing (DTS) to maximize the value of the installation plan.
Evaluation of Well Performance for the Slot-Drill Completion in Low- and Ultralow-Permeability Oil and Gas Reservoirs
Authors: Odunowo T.O.. O. , Moridis G.J.. J. , Blasingame T.A.. A. , Olorode O.M.. M. , Freeman C.M.. M.
Published: June 2014

Low- to ultralow-permeability formations require “special” treatments/stimulation to make them produce economical quantities of hydrocarbon, and at the moment, multistage hydraulic fracturing (MSHF) is the most commonly used stimulation method for enhancing the exploitation of these reservoirs. Recently, the slot-drill (SD) completion technique was proposed as an alternative treatment method in such formations (Carter 2009).

This paper documents the results of a comprehensive numerical-simulation study conducted to evaluate the production performance of the SD technique and compare its performance to that of the standard MSHF approach. We investigated three low-permeability formations of interest—namely, a shale-gas formation, a tight-gas formation, and a tight/shale-oil formation. The simulation domains were discretized with Voronoi-gridding schemes to create representative meshes of the different reservoir and completion systems modeled in this study.

The results from this study indicated that the SD method does not, in general, appear to be competitive in terms of reservoir performance and recovery compared with the more traditional MSHF method. Our findings indicate that the larger surface area to flow that results from the application of MSHF is much more significant than the higher conductivity achieved by use of the SD technique. However, there may exist cases, for example, a lack of adequate water volumes for hydraulic fracturing, or very high irreducible water saturation that leads to adverse relative permeability conditions and production performance, in which the low-cost SD method may make production feasible from an otherwise challenging (if not inaccessible) resource.
Optic Imaging of Two-Phase-Flow Behavior in 1D Nanoscale Channels
Authors: Wu Qihua , Bai Baojun , Ma Yinfa , Ok Jeong Tae , Neeves Keith B. , Yin Xiaolong
Published: June 2014

Gas in tight sand and shale exists in underground reservoirs with microdarcy (µd) or even nanodarcy (nd) permeability ranges; these reservoirs are characterized by small pore throats and crack-like interconnections between pores. The size of the pore throats in shale may differ from the size of the saturating-fluid molecules by only slightly more than one order of magnitude. The physics of fluid flow in these rocks, with measured permeability in the nanodarcy range, is poorly understood. Knowing the fluid-flow behavior in the nanorange channels is of major importance for stimulation design, gas-production optimization, and calculations of the relative permeability of gas in tight shale-gas systems. In this work, a laboratory-on-chip approach for direct visualization of the fluid-flow behavior in nanochannels was developed with an advanced epi-fluorescence microscopy method combined with a nanofluidic chip. Displacements of two-phase flow in 100-nm-depth slit-like channels were reported. Specifically, the two-phase gas-slip effect was investigated. Under experimental conditions, the gas-slippage factor increased as the water saturation increased. The two-phase flow mechanism in 1D nanoscale slit-like channels was proposed and proved by the flow-pattern images. The results are crucial for permeability measurement and understanding fluid-flow behavior for unconventional shale-gas systems with nanoscale pores.
Combining Geostatistics With Bayesian Updating To Continually Optimize Drilling Strategy in Shale-Gas Plays
Authors: Willigers B.J.A.. J.A. , Begg S.. , Bratvold R.B.. B.
Published: June 2014

We present a new methodology to evaluate subsurface uncertainty during the development of shale-gas plays. Even after many wells are drilled, the average well production and the variation of well performance (economics) remain highly uncertain. The ability to delineate a shale play with the fewest wells and to focus drilling in the most-productive areas is a major factor in commercial success.

The importance of probabilistic modeling in managing uncertainty in shale-gas plays is emphasized in several studies. The objective of this study is to develop a practical methodology that addresses these complexities and is dynamic, in the sense that the optimal drilling strategy can be continually updated as we learn the outcome of each well drilled.

Maximizing the returns from a shale-gas play is essentially a problem of choosing well locations and number of wells to optimize production volumes and rates. Drilling policies must take account of many already-drilled locations, possible new drilling locations, spatial dependencies between performance at those different (possible) well locations, and the extent of uncertainty concerning whether a well will be economical. These factors cause typical valuation methodologies to be impractical because of the "curse of dimensionality."

In this study, an unconventional play is divided into numerous segments. These segments are referred to as cells. In each cell, a fixed number of wells can be drilled. The chance of success (CoS) [of a well with a net present value (NPV) greater than zero] in any given cell is itself considered to be an uncertain variable. An initial probability distribution for the CoS of each cell is derived from analogous plays plus any available information about the specific play.

The methodology proceeds as follows. First, as each new well (or group of new wells) is drilled, the outcome is used in combination with the prior probability distribution (with Bayes theorem) to create an updated probability distribution for the CoS of the relevant grid cell. Thus, our initial estimate can be continuously updated as more actual outcomes are realized. Second, the influence of the new CoS on the surrounding cells, because of spatial correlation, is updated by use of indicator Kriging (IK), a geostatistical technique. This combination of Bayesian update (BU) and IK is referred to as the BU-IK method.

The methodology proposed in this study informs the development of drilling policies for shale-gas opportunities with a probabilistic model that accounts for the uncertainty in the CoS and its spatial dependency. The use of cells to represent a set of wells simplifies the analysis and greatly reduces the computing requirements. The methodology is applied to a well set from the Barnett shale in Texas.
Using Real-Time High-Resolution LWD Images to Navigate and Optimize Multi-Stage Completions in a Carbonate Reservoir
Authors: Janwadkar Sandeep , Murrell Paul , Thomas Mark
Published: June 2014

The Permian Basin of West Texas in North America is one of the most mature and prolific oil fields in the United States, continually evolving in production potential via the use of horizontal well drilling. Although initial well productivity has increased with new drilling and completion technologies, forecasting the success of a single well is still difficult because results may be inconsistent within the same section or across the play. This paper reviews the factors affecting well productivity and focuses on optimized completions design to grasp a better understanding of the geology and fracture network. Determining and identifying the zone of interest within the carbonate interval and then navigating within it with conventional LWD technology is a major challenge.

To overcome these challenges, real-time high-resolution LWD images were proposed. Azimuthal gamma ray and multiple propagation resistivity measurements were used to determine bed dip, correlate position within the reservoir and indicate formation porosity variations. Advanced LWD imaging tools provide visual confirmation of steering up and down within the reservoir and identify structural information, porosity changes, rock type, faults and fracture types.

Electrical images were incorporated as a crucial part of the completion strategy. Non-productive stages were eliminated by identifying and avoiding brecciated and faulted zones during completion, and improved completion efficiency and cycle time resulted in operator savings.

In conclusion, LWD images are used to more efficiently drain the reservoir by providing necessary information to stay longer in the target zone and optimize completion. LWD images also help explain production variances between wells targeting the same interval. This paper highlights sub-seismic faults and brecciated intervals that were not resolved using traditional gamma resistivity. By characterizing structural changes through the lateral, completion techniques can be customized to the specific well and maximize recoverable hydrocarbons. The new method enabled the lateral interval to increase from 77% in the offset well to 100% in-zone. The combination of factors, including better wellbore permeability, resulted in an 8% increase in oil production and 68% increase in gas production compared to the offset well during the first five full months of production.
Optimizing the Integration of 4D Seismic Data in History Matching: Which Data Should We Compare?
Authors: Sagitov Ildar , Stephen Karl D.
Published: June 2014

History matching by integrating time-lapse seismic with production data can become a more complex process. The additional constraints make it harder to find good models and this is made more difficult due to the nonlinearities encountered when predicting seismic behavior. A key aspect of this is the choice of domain in which to compare seismic data such as time domain or domain of inverted petro-elastic properties. We extend previous work where we examined the misfit surface from various domains by adding quantitative measures of nonlinearity in function of seismic on model parameters and analysing uncertainties in parameter estimates.

In this study we apply history matching to the models on the Schiehallion field. We compare the attributes of acoustic impedance derived from coloured inversion products to predicted acoustic impedance from a petro-elastic model. We call this a cross-domain comparison. To perform an alternative same-domain comparison, seismic prediction is based on the 1D convolution method. We then derive predicted pseudo impedance attributes, equivalent to those observed, using ’coloured inversion’. Models obtained in history matching using these two schemes are then examined.

Our results show that the outcome of history matching to seismic data is affected by the underlying static model conditioned to baseline 3D seismic in different domains which makes comparison of domains more difficult. It was demonstrated that cross-domain comparison of predicted impedances to observed seismic data increases non-uniqueness of parameter estimates. On the other hand, comparison in the same domain requires more modeling steps which adds to the nonlinearity because of narrowing frequency band.

Accurate reconciliation of predicted and observed seismic and production data via history matching is necessary for maximising the forecast capability of a simulation model. This significantly improves decision making by reducing risks and uncertainties in a field development.
Combining Pressure Falloff and Buildup Testing Using Wireline Formation Tester in Coal Bed Methane Environment
Authors: Osman Magdy Samir , Harfoushian Jack H. , Zerpa Bolivar C. E. , Thwaites Nick
Published: June 2014

Growing interest in gas reservoirs in nonconventional environments includes coal bed methane, which constitutes a potential important source of hydrocarbon gas in the UK but has been traditionally eclipsed by the conventional offshore oil and gas production. The current coal bed methane projects exist in different parts of the UK mainland. Drilling of these targets requires the use of minimum overbalance and nondamaging fluids.

The evaluation of coal bed methane reservoirs has its technical challenges. One of the challenges is to estimate the coal permeability by using both injection and production tests to ascertain coal cleat behavior. Although normal testing techniques can be used, interval testing using wireline can be more efficiently deployed to test individual coal bed seams. Traditionally, either an injection test or production test was applied to coal bed seams. In this paper we present a new approach that combines injection and buildup testing.

The methodology deploys a straddle packer string with a downhole pump on wireline. The packer spacing can be adjusted prior to deployment to suit the expected height of the coal bed to be tested. The tool is capable of both injection into and producing from the coal bed interval with the minimum storage volume. Downhole packer interval pressure is monitored on surface. Both the injection pressure and the drawdown pressure must be limited to avoid putting excessive force on the coal seam while maintaining single-phase flow.

Data from a recent application of the technique is presented for two different tested intervals. Obtaining permeability data from both falloff and buildup helps insure consistency between the tool data sets although some difference in the response between the two techniques results from the nature of the coal bed seam at each particular interval.
History Matching of the Norne Full-Field Model With an Iterative Ensemble Smoother
Authors: Chen Yan , Oliver Dean S.
Published: June 2014

Although ensemble-based data-assimilation methods such as the ensemble Kalman filter (EnKF) and the ensemble smoother have been extensively used for the history matching of synthetic models, the number of applications of ensemble-based methods for history matching of field cases is extremely limited. In most of the published field cases in which the ensemble-based methods were used, the number of wells and the types of data to be matched were relatively small. As a result, it may not be clear to practitioners how a real history-matching study would be accomplished with ensemble-based methods.

In this paper, we describe the application of the iterative ensemble smoother to the history matching of the Norne field, a North Sea field, with a moderately large number of wells, a variety of data types, and a relatively long production history. Particular attention is focused on the problems of the identification of important variables, the generation of an initial ensemble, the plausibility of results, and the efficiency of minimization. We also discuss the challenges encountered in the use of the ensemble-based method for complex-field case studies that are not typically encountered in synthetic cases.

The Norne field produces from an oil-and-gas reservoir discovered in 1991 offshore Norway. The full-field model consists of four main fault blocks that are in partial communication and many internal faults with uncertain connectivity in each fault block. There have been 22 producers and 9 injectors in the field. Water-alternating-gas injection is used as the depletion strategy. Production rates of oil, gas, and water of 22 producers from 1997 to 2006 and repeat-formation-tester (RFT) pressure from 14 different wells are available for model calibration. The full-field simulation model has 22 layers, each with a dimension of 46 × 112 cells. The total number of active cells is approximately 45,000.

The Levenberg-Marquardt form of the iterative ensemble smoother (LM-EnRML) is used for history matching. The model parameters that are updated include permeability, porosity, and net-to-gross (ntg) ratio at each gridblock; vertical transmissibility at each gridblock for six layers; transmissibility multipliers of 53 faults; endpoint water and gas relative permeability of four different reservoir zones; depth of water/oil contacts; and transmissibility multipliers between a few main fault blocks. The total number of model parameters is approximately 150,000. Distance-based localization is used to regularize the updates from LM-EnRML. LM-EnRML is able to achieve improved data match compared with the manually history-matched model after three iterations. Updates from LM-EnRML do not introduce artifacts in the property fields as in the manually history-matched model. The automated workflow is also much less labor-intensive than that for manual history matching.
Effects of Brine on Crude Oil Viscosity at Different Temperature and Brine Composition - Heavy Oil/Water Interaction
Authors: Gachuz-Muro Heron , Sohrabi Mehran
Published: June 2014

For decades, it has been observed that temperature has a significant impact on viscosity reduction, mainly, in heavy and extra-heavy oils where increasing the temperature will improve the flow of oil through the reservoir. Austad and his group have reported that three main ions (SO42−, Mg2+, Ca2+) are potential determining ions for improving oil recovery in carbonate rocks. Both of them must act together. Their studies focused on studying light oils. At the same time, they pointed out the importance of injected fluid/crude oil/rock interactions.

Water injection is the most widely used oil recovery technique which has been extensively applied globally in both light and heavy oil reservoirs for decades. Historically, the composition of injection water is dictated by the source of water available for injection. However, recent investigations have shown that the composition of the flood water can have a significant impact on oil recovery achived by water flood. Both total salinity and individual ions content of water have been shown to affect the performance of water flood. It has also been observed that interactions between water and crude oil may affect the oil viscosity. Most of the available research results are on light oil systems but the impact of water composition and its interactions with heavy oil have not been investigated.

In this paper, we have experimentally investigated the interactions between brine and heavy oil. The focus of the study was largely on the impact of brine on heavy crude oil viscosity. Four different heavy oil samples were selected from a group of reservoirs and tested in this study. Experiments were conducted using different types of water at different temperatures. Synthetic seawater, formation water, normal brine and distilled water were used as selected brines. The heavy oils were brought in contact with selected brines such that each sample (system) consisted of 80/20 (brine/heavy oil) volume percent. The viscosity and water contact of the each oil was measured before and after the oil had been in contact with brine.

The results of this paper indicate the crude oil viscosity may be altered due to contact with brine. The composition of brine as well as crude oil affect whether the oil viscosity increases, decreases or remains unchanged. The results are important for water injection and handling both on the surface and also in the reservoir.
The Effect of Well Orientation (Vertical vs. Horizontal) on CO2 Sequestration in a Water Saturated Formation-Saline Aquifer in Western Australia
Authors: Tsar Mitchel , Ghasemiziarhani Mohsen , Ofori Kofi
Published: June 2014

Unconventional saline aquifers have injectivity problems due to low to moderate permeability, thickness and porosity, of the potential injection zones. Therefore, optimum injectivity rates to allow for more cost-effective sequestration requires enhancement techniques such as hydraulic fracturing of the injection zones and /or horizontal injection wells. This study presents analysis of different CO2 saline reservoir trapping and investigates the effect of well orientation on the CO2 injection rates and cumulative storage. Reservoir simulation is used to study the effect of well orientation on injectivity, based on reservoir and core data from a water saturated formation/saline aquifer in Western Australia. The results highlight benefits of using horizontal well over vertical well in improving the efficiency with which the CO2 will fill the reservoir (E - Factor).
Marine and Coastal Sensitivity Mapping for Oil Spill Preparedness and Response
Authors: Nxumalo G. M. , Lee J. T. , Ross S. G.
Published: June 2014

This paper summarises the approaches used for desk-based sensitivity mapping and the alignment with international best practice guidelines. The primary focus is on available data sources for developing a robust baseline database and how these can be made accessible through interactive Geographic Information Systems (GIS) tools. The conclusions focus on the benefits of sharing information and key lessons learned for developing these collaboration tools.

Based on the most recent IMO/IPIECA sensitivity mapping guidelines this paper outlines a staged approach to sensitivity assessment. Initial desk-based mapping and sensitivity classification draws on existing data sources and remote sensing interpretation, which subsequently informs more detailed field surveys. This approach enables rapid assessment of potentially sensitive locations to provide an immediate overview of risks, ahead of targeted field assessments to fill data gaps in support of the contingency planning process.

A key tool for successfully implementing these projects has been the use of GIS. In addition to providing the analytic tools and central data and document repository, web-based GIS viewers provide instant access to project data and metadata from any location. Web editing tools enable planners and response personnel to plot and share proposed locations for response resources (e.g. staging areas) during the response planning stage. This approach dramatically reduces reliance on traditional paper mapping during planning stages while still allowing responders to produce field maps for working in a response situation.

In the wake of the Deep-water Horizon incident many oil and gas operators are re-examining their risk exposure with regard to potential accidental oil spill incidents. In many instances this now includes consideration of larger potential impact zones resulting from a worst case oil spill scenario. Key to successful planning is understanding where the potential sensitive coastal and offshore environmental and socio-economic resources are, and communicating these effectively to incident management specialists, regulatory agencies and other stakeholders.
Mercury Guideline for the Norwegian Oil and Gas Industry
Authors: Naerheim Jakob
Published: June 2014

Mercury has been identified as a major health hazard in the oil & gas industry. The reason is on the one side the presence of mercury and on the other side its neurotoxicity and its ability to accumulate. Mercury may be found in crude oil and natural gas condensate and follows the production flow in different chemical forms. Reservoirs with sweet crude oil and high temperature/pressure seem to experience the highest content of mercury.

To help the Norwegian petroleum industry to control the risk of mercury exposure, a guideline has been developed. The experience and needs of the different actors in the industry have been collected, shared and discussed to compile this guideline. The objective of this work has been to control the health risk associated with handling and processing crude oils and natural gas condensates that contain mercury.

The guideline has been developed, tested and implemented in the industry. It has in some instances been an eye opener to reveal a hidden hazard, in other case it has been an effective transfer of good practice between companies. Prior to its release the guideline was field tested in real offshore maintenance activities. The experiences from the testing have been implemented into the final version of the guideline.

Joining forces to prepare industry guidelines is a fruitful way of compiling and sharing best practise. The mercury guideline has acted as an eye opener to the industry, and has enabled the industry to better control mercury exposure.
The Value of Safety Indicators
Authors: van Kampen Jakko , van der Beek Dolf , Groeneweg Jop
Published: June 2014

Organizations are searching for ways to gain insight into the level of safety in their company so that additional measures can be taken when necessary, and so the effectiveness of interventions can be measured. That said, measuring safety, health, and the environment is not easy. A survey among members of the Netherlands Society for Safety Science (NVVK) was conducted and analyzed. Companies that fall under the European Union SEVESO II Directive were analyzed separately. This study shows which indicators are used the most in the industry. It also shows that the respondents take safety very seriously; on average, they use 15 of the 37 safety indicators stated. This study also asks what the organizations do with these indicators in practice. Much of the collected information is not used as an indicator to improve organizations, even those that are considered to be of utmost importance for safety.

The number of indicators used in organizations proved to be a reasonably good measure of discriminating between companies with a good or not-so-good personal safety performance, as measured by self-reported lost-time injury frequency (LTIF). It cannot be concluded from this that the use of more indicators leads to fewer accidents. It is more likely that good organizations gather and use more information to steer safety efforts, and that this leads to fewer personal accidents. What is also evident is that more-successful organizations make more use of specific types of indicators. Notably, neither the amount nor the nature of indicators collected can be related to process safety performance as measured by self-reported “loss of containment” events. This could be because of the lack of standardization with respect to what is measured and how it is standardized. At present, there are no set indicators that can be collected from organizations that can reliably discriminate between organizations with no or few or organizations with many process-related incidents. This study legitimizes the continued pursuit of suitable “leading indicators” for process safety.
Innovations in Sustainable Shale Gas Water Managment High Recovery Reverse Osmosis Case Study
Authors: Kimball R. J. , Locke A. L.
Published: June 2014

Natural gas production from low permeability shale formations (shale gas) has recently become economically viable due to technological advancements in horizontal drilling and hydraulic fracturing. Shale gas is present in numerous and large "basins" around the world, including across the United States, and has been largely untapped due to the very "tight" nature of shale rock. With horizontal drilling and hydraulic fracturing, previously inaccessible natural gas is made to flow through newly formed fractures in the shale to production wells.

As a result of this technology, natural gas is now one of the world’s fastest growing energy sources. The development of unconventional sources, such as coal seam gas, will grow dramatically due to vast basins in the United States, and Europe. These reserves are being tapped with new techniques for detection, hydraulic stimulation and extraction.

Leveraging any natural resource requires responsible environmental management. Development includes many protective measures, with special concern for water resources and water quality. There is considerable debate about environmental concerns related to produced water. Our industry has a role to identify and apply robust, reliable and efficient scientific and engineering methods to help protect water supplies and the environment.

Water management is one of the biggest operating issues for resource developers. While well development may require 4-5 million gallons of water per horizontal well, more liquid is produced throughout the gas well’s lifecycle containing constituents at concentrations much higher than in surface water—all of which requires management through treatment and beneficial use. To protect fresh water resources and control treatment costs, resource developers are seeking innovative treatment and reuse options.

This paper provides detailed information and context from case studies including references of relevance to the gas field produced water characteristics of representative Europe and American gas fields.
Improvement of Chemical Working Environment in Shaker Room with Enclosed Shaker Design and Optimized Ventilation Rates
Authors: Aase Bodil , Jensen Ellen Katrine , Omland Tor Henry
Published: June 2014

Drilling operations require use of drilling fluid and solids control equipment to remove cuttings from the well. To maintain the drilling fluid at its desired properties it is essential to have efficient solids removal, which requires good solids control equipment in addition to good routines and practice for inspection of the shale shakers. Solids removal takes place in the shaker room, where the return fluid from the well is processed by shale shakers. Chemical emission of volatile compounds occur as the warm drilling fluid passes through the screens in the shaker and cuttings are discharged, and despite the use of ventilation system the emissions highly effect the working environment and point out the shaker room as a hot spot for occupational exposure.

During an onshore test of various shakers, factors expected to effect the chemical working environment while using oil based drilling fluid was examined. The factors were traditional open versus enclosed shaker design / front hood, and high and low ventilation rate. The evaporation level was monitored with a real time instrument for measurement of volatile organic compounds, while the level of oil vapour and oil mist were captured with filter and adsorbent tube sampling. The test methodology has been evolved from prior offshore and onshore tests (Bråtveit et al. 2009; Peikli et al. 2010; Steinsvåg et al. 2011; Aase et al. 2012).

The results from the chemical emission measurements showed that the separation system with highest degree of enclosure, i.e. fully enclosed, gave the lowest values, thus, provided the best chemical working environment. For semi-enclosed solutions, it was possible to reduce the emissions through optimizing the ventilation rate. However, the chemical emissions were still above the tests acceptance criteria. For a fully open system it was not possible to apply ventilation only in order to control chemical emissions to an acceptable level. As a result of the test all participating shaker suppliers have initiated design improvements to achieve a better chemical working environment in the shaker room.
A Generic Model to Assess Major Incident Frequencies for Offshore Assets
Authors: Emery R. J. , Flynn J.. , Smith D.. , Linzi P
Published: June 2014

Quantitative risk assessments (QRAs) for offshore oil and gas exploration and production assets are commonly used in the industry to demonstrate that risks are within tolerable limits. The results of these QRAs are included in an installation’s Operations Safety Case, which is prepared in response to the requirements of Regulation 7 of the Offshore Installations (Safety Case) Regulations 2005 (SI 2005/3117). These results provide part of the demonstration that the risks are managed to ALARP and are also used as input into the Justification for Continued Operations. A limitation of these assessments, however, is that a realistic comparison between assets is often not possible since methods, input data and assumptions vary from one QRA to another, in some cases quite widely. These variations may include the use of differing leak frequency databases, differing parts count definitions, ignition models, and fatality and impairment probabilities. In addition, QRAs do not focus on potential asset, or environmental consequences which are of significant interest to operators and equity partners.

This paper presents a methodology for assessing Major Incident Frequencies to enable a realistic comparison, on a like for like basis, of a range of asset types, which have been assessed using differing QRA methodologies. The methodology presented within this paper has been applied to various assets including fixed manned and unmanned installations, FPSO’s and FSO’s. The results indicate that the methodology developed is sufficiently robust to allow a meaningful comparison to be made between different types of assets, and provides an improved estimation of the overall major incident risk frequency compared with that which is typically presented in installation specific safety cases.