bluuebunny/crossref_metadata_2025 huggingface dataset:
The Impact of Complex Nanofluid Composition on Enhancing Regained Permeability and Fluid Flowback from Tight Gas Formations and Propped Fractures
Authors: Champagne Lakia M. , Zhou Hui , Zelenev Andrei S. , Lett Nathan
Published: June 2014

A continuing challenge in hydraulic fracturing of tight gas formations is associated with remediation of formation damage caused by fluid invasion into the porous media. Numerous studies documenting the use of complex nanofluids and surfactants to remediate formation damage have been reported. Recent publications have demonstrated that complex nanofluid additives resulted in lower pressures to displace injected frac fluids over conventional surfactants, and led to greater enhancement of gas and water production. These findings were also confirmed by several recent statistical analyses that took into consideration differences in the properties of treated wells. Many field case studies and supplementary laboratory data have illustrated benefits of complex nanofluid treatment over conventional surfactants. While these publications describe the successes of complex nanofluid treatment, the influence that the formulation composition has on its performance has not been fully investigated. In the present study, we prepared complex nanofluids with different chemical compositions and examined their performance in fluid recovery tests using columns packed with sand, ceramic proppant, and shale, as well as their ability to enhance permeability of sandstone cores to gas. We have established that performance of complex nanofluids in these applications was dependent on the amount of microemulsifed solvent in the original formulations and that optimal performance across all applications was achieved with a complex nanofluid formulation with a near-balanced composition.
"Squimulation": Simultaneous Well Stimulation and Scale Squeeze Treatments in Deep Water, West Africa
Authors: Patterson D. , Kendrick M. , Williams W. , Jordan M.
Published: June 2014

In a deepwater West African field the relatively small number of high-cost, highly productive wells, coupled with a high barium sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery.

The nature of the well completion strategy in the field (frac packs for sand control) had resulted in some wells with higher than expected skin values due to drilling fluid losses, residual frac gel, fluid loss agents, and fines mobilization within the frac packs.

The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale inhibitor packages to deep water wells. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (>20ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides a cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments. The four field treatments that were performed demonstrate how these coupled applications have proven very effective at both well stimulation/skin reduction and scale inhibitor placement prior to and after seawater breakthrough. The term "squimulation" is used by the local operations team to describe this simultaneous squeeze and stimulation process.

Many similar fields are currently being developed in the Campos basin, Gulf of Mexico, and West Africa, and this paper is a good example of best-practice sharing from another oil basin.
Coiled Tubing Operational Guidelines in Conjunction with Multistage Fracturing Completions in the Tight Gas Fields of Saudi Arabia
Authors: Al-Gazal Mohammed , Abel Justin Tate , Wilson Stuart , Wortmann Henry , Johnston Bryan
Published: June 2014

Open hole multistage fracturing (MSF) completions are becoming standard practice in the south gas fields development in Saudi Arabia with more than 25 wells completed to date using open hole packers and selective port technology.

Overall, the production results from the use of MSF completions have been very positive and the forecast is that MSF technology usage will grow considerably over the next several years. In general, MSF completions provide an excellent advantage in that they are intervention-less in their standard mode of operation. An aspect that is evolving is the secondary use of coiled tubing (CT) to handle the planned and unplanned (contingency) operations occasionally required to reach well production objectives. Without optimum operational planning and the selection of correct CT downhole tools, completion problems can be encountered and this ultimately can result in the job objective not being reached at all or only at increased costs. In addition, the use of CT to function ball-activated ports to shut off zones or to re-stimulate is starting to be appreciated.

This paper presents MSF case studies where CT has been deployed and investigates the operational impact and productivity enhancement. Correlations taken from the key hardware variables, such as fracturing port size and type, motor type, mill bit type, and CT size, are also considered and analyzed.

Following the lessons learned and best practices from these experiences, with correct implementation, the findings from this paper should increase the potential for successful multistage completion operations and ultimate improvements in productivity. These guidelines can thus be transferable to other operators using similar MSF completion technologies.
Test of SAGD Flow-Distribution-Control Liner System in the Surmont Field, Alberta, Canada
Authors: Stalder John
Published: June 2014

The Surmont Well Pair 102-06 started steam-assisted-gravity drainage (SAGD) operation in April 2009 with flow-distribution control (FDC) built into the horizontal liners for both the injection and the production wells. After preheat steam circulation, this liner system has allowed operation without a toe tubing string in either completion and has delivered superior steam-chamber development and overall performance. The design also allowed reducing the liner and casing size for the injection well. Future SAGD-well design may benefit by further reduction in liner and casing sizes for both the injector and producer, which could allow longer completions by reducing liner drag and increasing directional-drilling flexibility. Ultimately, these SAGD-well design changes could increase the amount of reservoir developed per well and per well pad, using longer wells and more wells per pad while achieving superior SAGD performance.
Pore-Scale Modeling of Waterflooding in Mixed-Wet-Rock Images: Effects of Initial Saturation and Wettability
Authors: Zhou Y.. , Helland J.O.. O. , Hatzignatiou D.G.. G.
Published: June 2014

We simulate transient behavior of viscous- and capillary-dominated water invasion at mixed-wet conditions directly in scanning-electron-microscope (SEM) images of Bentheim sandstone by treating the pore spaces as cross sections of straight tubes. Initial conditions are established by drainage and wettability alteration. Constant rate or differential pressure is imposed along the tube bundle. The phase pressures vary with positions along the tube length but remain unique in each cross section, consistent with 1D core-scale models. This leads to a nonlinear system of equations that are solved for the interface positions as a function of time. The cross-sectional fluid configurations are computed accurately at any capillary pressure and wetting condition by a semianalytical model that is based on free-energy minimization. The fluid conductances are estimated by newly derived explicit expressions that are shown to be in agreement with numerical computations performed directly on the cross-sectional fluid configurations.

An SEM image of Bentheim sandstone is taken as input to the developed model for simulating the evolution of saturation profiles during waterfloods for different flow rates and several mixed-wet conditions, which are established with various initial water saturations and contact angles. It is demonstrated that the simulated saturation profiles depend strongly on initial water saturation at mixed-wet conditions. The saturation profiles exhibit increasingly gradual behavior in time as the contact angle, defined on the oil-wet solid surfaces, increases or the initial water saturation decreases. Front menisci associated with positive capillary pressures promote oil displacement by water, whereas for large and negative capillary pressures at small flow rates, oil displaces water because the associated front menisci retract. This results in the development of pronounced gradual saturation fronts at mixed-wet conditions. The waterfloods simulated at conditions established with a large initial water saturation and small contact angle on the oil-wet solid surfaces exhibit sharp Buckley-Leverett saturation profiles for high flow rates because the capillary pressure is small and less important. The shape of the saturation profiles is interpreted on the basis of the simulated capillary pressure curves and the corresponding fluid configurations occurring in the rock image.
Double-Layer Expansion: Is It a Primary Mechanism of Improved Oil Recovery by Low-Salinity Waterflooding?
Authors: Nasralla Ramez A. , Nasr-El-Din Hisham A.
Published: June 2014

Literature review shows that improved oil recovery (IOR) by low-salinity waterflooding could be attributed to several mechanisms, such as sweep-efficiency improvement, interfacial-tension (IFT) reduction, multicomponent ionic exchange, and electrical-double-layer (EDL) expansion. Although these mechanisms might contribute to IOR by low-salinity water, they may not be the primary mechanism. Therefore, the main objective of this study is to investigate if the mechanism of EDL expansion could be the principal reason for IOR during low-salinity waterflooding.

Low-salinity water results in a thicker EDL when compared to high-salinity water, so we tried to eliminate the effect of low-salinity brines on double-layer expansion to show to what extent IOR is related to EDL expansion caused by low-salinity water. The double-layer expansion is dependent on the electric surface charge, which is a function of the pH of brine; therefore, the pH levels of low-salinity brines were decreased in this study to provide low-salinity brines that can produce a thinner EDL, similar to high-salinity brines. ζ-potential measurements were performed on both rock/brine and oil/brine interfaces to demonstrate the effect of brine pH and salinity on EDL. Contact angle and coreflood experiments were conducted to test different brine salinities at different pH values, which could assess the effect of water salinity and pH on rock wettability and oil recovery, and hence involvement of EDL expansion in the IOR process.

ζ-potential results in this study showed that decreasing the pH of low-salinity brines makes the electrical charges at both oil/brine and brine/rock interfaces slightly negative, which reduces the double-layer expansion caused by low-salinity brine. As a result, the rock becomes more oil-wet, which was confirmed by contact-angle measurements. Moreover, coreflood experiments indicated that injecting low-salinity brine at lower pH values recovered smaller amounts of oil when compared to the original pH because of the elimination of the low-salinity-water effect on the thickness of the double layer. In conclusion, this study demonstrates that expansion of the double layer is a dominant mechanism of oil-recovery improvement by low-salinity waterflooding.
Refined Adaptive Gaussian Mixture Filter - Application on a Real Field Case
Authors: Valestrand Randi , Nævdal Geir , Shafieirad Ali , Stordal Andreas S. , Dovera Laura
Published: June 2014

Over the last decade the ensemble Kalman filter (EnKF) has attracted attention as a promising method for solving the reservoir history matching problem: Updating model parameters so that the model output matches the measured production data. The method possesses unique qualities such as; it provides real time update and uncertainty quantification of the estimate, it can estimate any physical property at hand, and it is easy to implement. The method does, however, have its limitations; in particular it is derived based on an assumption of a Gaussian distribution of variables and measurement errors.

A recent method proposed to improve upon the original EnKF method is the Adaptive Gaussian mixture filter (AGM). The AGM loosens up the requirements of a linear and Gaussian model by making a smaller linear update than the EnKF and by including importance weights associated with each ensemble member at computational costs as low as EnKF. In this paper we present a refined AGM algorithm where the importance weights are included in the calculation of the apriori and the aposteriori covariance matrices. Moreover, in this paper the AGM algorithm is for the first time applied to a real field study.

To validate the performance of AGM the results are compared with the EnKF, with and without distance based localization. Several statistical measures are used to validate the performance of the filters, and we are able to distinguish the performance of the different filters. In particular all the methods provide good history match, but we see that the AGM stands out by better honoring the original geostatistics and by providing consistent predictions when rerun is performed.
Estimation of Relative Permeability by Assisted History Matching Using the Ensemble Kalman Filter Method
Authors: Li Heng , Chen Shengnan Nancy , Yang Daoyong (Tony) , Tontiwachwuthikul Paitoon
Published: June 2014

An ensemble-based history technique has been applied to implicitly estimate three-phase relative permeability curves from production data. A power law representative of relative permeability curves is used. Both endpoints and shape factors of relative permeability curves are included in state vectors that are updated sequentially by assimilating observation data. This method has been validated by accurately evaluating relative permeability in a synthetic reservoir with 2D, three-phase flow. It is shown from the synthetic case that good estimation of relative permeability curves can be obtained by assimilating the observed oil rates, gas/oil ratios, and bottomhole pressures of production wells. Both shape factors and endpoints of relative permeability curves are accurately evaluated; however, a larger ensemble size is needed to avoid filter divergence. Compared with the existing implicit methods, the ensemble-based history matching technique does not require the gradient of the objective function, which makes the technique easy to implement.
Some Results of Fracturing with the Single-Point Entry Technique
Authors: Swift V.N. , Jennings J.W. , Bauman W.E. , Huitt J.L.
Published: June 2014

Fracturing with the single-point entry technique is discussed for the Big Piney and Patrick Draw fields, Wyo., and the Bijou field, Colo. In the single-point entry technique, the wellbore is notched at a selected point. The well is fractured and then is produced by way of the single fracture. The results indicate that fracturing treatments can be performed more easily through the single entry than through perforations, and the production histories available thus far indicate that wells fractured with the single-point entry technique have higher productivities than those fractured by conventional wellbore preparation.

Introduction

The single-point entry technique of fracturing for well stimulation per se was first used in the Big Piney field, Wyo., in June, 1959. This technique of fracturing, in which the wellbore is notched for the fracture placement and a single, high-flow-capacity fracture is used for the production stimulus, was originally considered to have its greatest potential in secondary recovery schemes and in the control of gas and/or water coning. However, during the development of the techniques for notching the wellbore and for selection and placement of the fracture propping agent, it became apparent that for a number of reservoirs conventional fracturing techniques did not provide the well stimulation that the single-point entry technique would provide. Thus, the mechanics of the technique was adapted for use as a production stimulus during primary recovery.

Since June, 1959, single-point entry fracturing has been used in several hundred cases for well stimulation. In a majority of the cases, a comparison of the results with those obtained by conventional fracturing in a perforated interval cannot be made because the available data are insufficient. However, sufficient data are available for three fields in the Rocky Mountain area to allow an evaluation of the usefulness of the single-point entry technique in performing fracturing operations. These fields are the Big Piney and Patrick Draw fields in Wyoming and the Bijou field in Colorado. Also, for the Patrick Draw field, productivity index data are available to enable a comparison of the results of fracturing to be made, and sufficient production history on the Big Piney field makes it possible to compare the performance of the wells fractured conventionally with those wells fractured by the single-point entry technique. In this paper, fracturing operations in the three fields listed are discussed as case histories.
Determining Areal Permeability Distribution by Calculations
Authors: Kruger W.D.
Published: June 2014

Methods for analyzing flooding or cycling projects by means of two-dimensional flow calculations are presented in the literature. The use of these methods allows the determination of optimum operating conditions for such projects and provides information on pattern efficiencies, relative flow rates, pressure distributions and floodout histories. The accuracy of such analyses depends on the basic reservoir data employed, especially the absolute permeability distribution in the reservoir; however, absolute permeability data normally are determined from well flow tests and/or core measurements and are so limited in quantity and quality that they do not adequately describe the reservoir flow properties.

A calculation procedure is presented for determining the areal permeability distribution in the reservoir. Use of the procedure allows verification of the basic reservoir data through the matching of past reservoir conditions, thereby providing proper data for reliable predictions of future operations. The calculation procedure is a numerical technique based on a mathematical model of the reservoir and is designed for solution by means of an electronic digital computer.

Results from field application of this procedure are presented. Permeability distributions from measured data are compared to those calculated to indicate the need for the analysis. Comparisons of field-measured and calculated pressure distributions are given to establish the validity of the calculation procedure.

The conclusions of this paper areuse of the calculation provides data that allow a match of past reservoir conditions and thus reliable prediction of future operations; andthe procedure should, where applicable, be used to provide adequate reservoir data for use in two-dimensional flow calculations and related reservoir analyses.

Introduction

One means of providing more precise engineering control over reservoir operations during all stages of depletion is to develop some type of model to simulate the reservoir, using information developed from the behavior of the prototype to predict the performance of the actual reservoir. The use of mathematical rather than physical models for this purpose has been gaining in importance recently because of the application and availability of electronic computers. Mathematical models avoid instrumentation difficulties and allow easier handling of large-scale problems. At present, analyses employing two-dimensional models are common, and thought is being given to the use of models in three dimensions. The use of multi-dimensional models is necessary to show not only what is occurring in the reservoir, but also where in the reservoir the phenomena of interest are taking place.
SPE Dives Into the Gender Diversity Pool
Authors: Capello Maria Angela
Published: June 2014

With the ever increasing global demand for energy, the oil and gas industry must improve and anticipate its talent management needs by considering the current workforce profile, in which female employees are the minority. Being a traditionally male-dominated industry, gender-diversity concepts only recently have found their way into corporate policies, executive managers' desks or into Board of Directors meetings. In many cases, the inclusion of women in leadership roles is far from being a reality for companies in the up-and down-stream sectors.

This article summarizes some of the results of the global scale efforts of the Society of Petroleum Engineering (SPE) towards the establishment of new paths to exchange lessons learned, and the creation of new networking opportunities for its female members. Up to now, the SPE is the only oil and gas professional society that consistently has promoted the empowerment and progress of its female members with dedicated activities since the late 80's, in a 30-year pioneering role.

More actions are certainly needed, but this SPE visionary effort must be shared and celebrated.
Modelling of Cold Heavy-Oil Production With Sand For Subsequent Thermal/Solvent Injection Applications
Authors: Rangriz Shokri Alireza , Babadagli Tayfun
Published: June 2014

Although proved beneficial and economic for thin reservoirs, the cold heavy-oil production with sand (CHOPS) method has several limitations. The sand produced during CHOPS changes the geomechanical and petrophysical properties continuously and results in open channels in the reservoir known as wormholes. Also, the CHOPS method results in a low oil recovery (8–10% original oil in place). This entails a follow-up enhanced-oil-recovery (EOR) process, which is always an option for further exploitation, referred to as post-CHOPS. Assessment of such a process through numerical simulation, as the most inexpensive yet most powerful tool, necessitates a comprehensive modelling approach to capture its dynamic physical nature. Only through such a realistic model can one obtain reasonably reliable reservoir characteristics after CHOPS that are critically important to assess post-CHOPS applications. To this end, we implemented a fractal pattern of different kinds by use of a diffusion-limited aggregation (DLA) algorithm as wormhole domain with a partial dual-porosity approach and a step-by-step simulation technique, taking advantage of a simple mathematical model to integrate the sand-production data with fractal patterns. The wormhole network is assumed to grow with more sand production, respecting geological conditions and well perforation. Moreover, its effective properties and the contained fluid can be controlled along its length and pattern at different steps. Such an option is of great assistance in the history-matching process. The model was validated successfully with available Alberta field data. As a preliminary step to post-CHOPS, several thermal, solvent, and hybrid combinations of both scenarios were considered. The proposed method for CHOPS modelling is a useful approach to initiate a quick post-CHOPS study in practice if sand production history is provided. One may also take advantage of its compatibility with any black-oil, compositional, or thermal simulators.
Sampling While Drilling: An Emerging Technology
Authors: Villareal Steven , Pop Julian , Bernard François , Baxter Martin , Hakam Ahmad , Firth Andy , Megat Amanda , Fey Scott , Haq Shahid Azizul , Vahi Nitin
Published: June 2014

Even though it is the early days of the realization of sampling-while-drilling (SWD) as a service, a picture of what might be achievable in practice is beginning to emerge. Previous SWD experience has demonstrated that the sampling process may be controlled sufficiently well that relatively clean samples may be acquired when sampling aquifers drilled with water-based muds (WBMs), and it has demonstrated that the SWD tool and sensors used are capable of operating effectively while withstanding the drilling process. On the basis of this experience, operational guidelines have been formulated, particularly regarding the most opportune time to sample during the drilling process.

The first part of the paper describes SWD in a high-angle appraisal well drilled to assess the continuity and quality of several target sands and to establish the degree of continuity of these sands with the main field. The well was drilled by use of an oil-based mud (OBM). Samples would be acquired after the well had reached total depth so that the most appropriate sampling points could be identified by means of openhole logs. Multiple water-, oil-, and gas-bearing formations were identified. Sampling duties were split between the SWD tool and a drillpipe-conveyed wireline sampling (WLS) tool in an attempt to rationalize the sampling program of the well. To enable a comparison of the relative performance of the two tools, two oil-sampling stations were chosen where multiple samples would be acquired under similar operating conditions by both tools. In addition, water samples were collected at two stations by the SWD tool and scanning was performed at one (wet) gas station to confirm the formation-fluid type. Laboratory analysis of the oil samples at the common stations showed that the contaminations and fluid properties of the samples acquired by the two sampling tools were very similar.

The second part of this paper describes results obtained in an appraisal well and sidetrack in a different field. Both pilot and sidetrack were high-angle wells drilled by use of OBMs. The purpose of these wells was to identify and evaluate the commercial potential of unproduced hydrocarbon-bearing zones. Both wells were drilled to total depth before conducting sampling operations, and no wireline operations were planned in either well. Five oil samples were acquired in the pilot well in two zones, and four oil samples and two water samples were recovered in the sidetrack.

The results obtained during the SWD operations described suggest that it is possible to consistently acquire quality formation-fluid samples during drilling operations, even under less-than-optimal sampling conditions and strict time-on-station constraints. The quality of the samples recovered is sufficient to perform reliable pressure/volume/temperature (PVT) analyses.
Reservoir Conformance Control in Oilfields Using Silicates: State-of-the-Arts and Perspectives
Authors: Lakatos István , Lakatos-Szabó Julianna
Published: June 2014

The paper is devoted to overview of conformance treatments using silicates. As shown, the history of the silicate conformance control goes back many decades, but its benefits and field potentials were not really appreciated for a long time. Until now, the different silicate-based technologies have been used more than hundreds times in Hungary, Serbia, Norway, USA, Oman and other countries. Injection of silicates aimed at water shutoff and profile correction in producers and injectors, restriction of gas conning in gas-capped oil reservoirs, blocking of vertical CO2 migration in a collapsed well, water shutoff in reservoirs having extremely high permeability and faults and even improving sweep efficiency in CO2 flooding. Results of pilots and routine application were critically analyzed from different points of aspects. Recently, the advanced methods based on simultaneous application of polymers, urea, humates, nanoparticles, etc. recognizing that the pure silicate gels have some disadvantageous properties under reservoir conditions. Combination of silicates with different chemicals improves significantly the stability, flexibility of such inorganic gels and makes it possible to cure great variety of conformance problems in both porous and fractured reservoirs. The field jobs demonstrate ample examples for outstanding and positive statistics and lessons to learn. In addition, the application of those exclusively environmental friendly chemicals may open new vistas in improvement of well performance of both producers and injectors.
Model Studies of Oil Displacement from Thin Sands by Vertical Water Influx from Adjacent Shales
Authors: Bobek J.E. , Bail P.T.
Published: June 2014

In reservoirs containing soft shales interbedded with oil-producing sands, it is possible to have water movement from the shales into the sands during reservoir depletion.

This paper presents the results of scaled flow-model tests performed to investigate the efficiency of oil displacement by this vertical influx of water into oil-producing sands. In these model tests, the effects of rate of influx and rock wettability were considered.

Oil recoveries by shale-water influx and by water flooding were compared after 0.4 hydrocarbon volume of water entered the producing sand. This comparison was made for water-wet and oil-wet systems. In water-wet sand, shale-water influx produces slightly less oil than conventional water flooding; in oil-wet sand, shale-water influx produces about one-half as much oil as conventional water flooding. In another type of comparison, it was found that shale-water influx followed by water flooding recovers less oil than water flooding alone. This is true for both water-wet and oil-wet sands. A comparison of tests run at different rates of shale-water influx shows that oil recovery is insensitive to rate in water-wet sand; in oil-wet sand, oil recovery decreases with decreasing rate of influx.

Introduction

Localized subsidence of the earth's surface has accompanied the depletion of some oil reservoirs, particularly in California, along the Texas Gulf Coast, and in the Bolivar Coastal fields of Venezuela. Subsidence occurs when fluid withdrawals reduce the pressure in the reservoir. The reasons for subsidence accompanying a reduction in reservoir pressure are not known with certainty. However, there is considerable evidence that compaction of soft shale beds adjacent to producing oil sands can be a major cause of this subsidence. When the shales compact, a limited amount of water moves from the shales into the producing sands. A schematic illustration of this oil-producing mechanism is shown in Fig. 1. As the pressure in the sand declines due to oil production, a predominantly vertical pressure gradient develops at the sand-shale boundary. This causes water to move from the shale into the sand as indicated by the solid arrows.

This paper reports the results of scaled flow-model tests to investigate the efficiency of oil displacement by the vertical influx of shale water into producing sands.
Engineering the Oil Loan
Authors: Sonosky Jerol M.
Published: June 2014

Introduction

Several discussions have appeared in the literature recently regarding the data required and the factors involved in determining the amount of money which a bank may loan on oil and gas production. The purpose of this paper is to present the actual mechanics of applying these factors, pointing out their importance in the determination of loan value. The required data and applicable factors will be presented, including a step-by-step analysis of the procedures to be used. Also, examples will be discussed to present the type of results obtained and decisions required for loan analyses at various stages of reservoir depletion.

It should be kept in mind that, although the criteria presented are typical, they are by no means final, because the proper solution of the problem involves many variables which may affect each property differently. Furthermore, the actual evaluation may require additional types of analyses other than those presented, depending on the type of loan, operator, property, etc. This discussion is intended as a guide for the engineer whether he works for an operator, consultant or bank - in determining the amount of loan which a given property can safely handle so that he may properly advise his management of the engineering validity of the transaction.
Coking Behaviour During Visbreaking
Authors: Saxena Atul , Diaz-Goano Carolina , Dettman Heather
Published: June 2014

Previously, nuclear-magnetic-resonance (NMR) carbon-type-analysis data were used to develop a mathematical model of mild thermal conversion (visbreaking) of Athabasca bitumen (Chan et al. 2006). In that work, the major reaction pathways followed during visbreaking were identified. This approach is being extended in the current work to model the visbreaking behaviour of five different oils from different geographical locations around the world. This paper shows the correlation of residue conversion with the contents of different carbon types for five heavy oils from four continents.

During visbreaking runs, operators intend to maximize process yields. This is achieved through increasing process severity by raising temperature. However, if the temperature is too high, coke forms. This maximum temperature varies with different crude oils; therefore, as refinery feedstock composition changes, so does the onset of coking temperature. Coke is a hydrocarbon material that has low hydrogen content and is insoluble in the oil. Consequently, this precipitates in the reactor, eventually causing an unscheduled unit shutdown. We have found that contents of specific carbon types in the feed oils correlate with coke formation. This correlation allows prediction of the quantities of coke that will form under the chosen visbreaking (mild thermal) conditions and the "maximum" quantities of coke that would form under coking (severe thermal) conditions.
A New (3D MUDSYST Model) Approach to Wellbore Strengthening While Drilling in Depleted Sands: A Critical Application of LCM and Stress Caging Model
Authors: Bassey Akong , Dosunmu Adewale , Iorkam Azoom , Otutu Friday , Ukoha Joshua , Awe Ayodele Sunday , Alabi Tunde
Published: June 2014

Abstract

With the continued growth of drilling activities and the cost of performing them in depleted sands, loss of productive time is more important than ever. For years the use of LCM has been the preferred way for treating lost-circulation problems (Messenger 1981). However, the lost circulation problem was not totally resolved. Recent studies have shed much light on its cause and potential solutions. However, wellbore strengthening or stress cage implementation has been recognized as an effective means of dealing with lost circulation during drilling operations. One of the mechanisms developed for strengthening a wellbore has been to prop induced and existing fractures with particulate lost circulation materials (LCM) to effectively increase hoop stress in the near wellbore region. However, a good understanding of this mechanism is necessary in order to avoid a potentially flawed design and implementation process which could adversely affect job success during well operations. One of the main issues is depleted sand/shales stringers stability under the strengthening conditions. This paper will describe those factors which are important in designing wellbore strengthening jobs and address the conditions necessary to help ensure depleted sands stability, as determined through geomechanics analysis. The strengthening of a wellbore by propping fractures has been discussed in a previous investigation (Wang et al. 2007a). In this paper, various parameters that affect the strengthening of the wellbore are addressed in detail. In-depth discussion of how each of those parameters affects the process of wellbore strengthening will be presented. This study was accomplished using a boundary element numerical analysis coupled with the linear elastic theorem. Hence, the stress cage concept is an approach developed to enhance wellbore pressure containment (WPC). It has been found that a weak wellbore can contain much higher pressure if the wellbore fluid is treated with particulates and as such understanding the mechanism of stress caging is recommended to design the treatments for specific field application and to advance the development of the technology for application across a wider mud weight window and with a higher success rate while drilling in depleted sands. On-the-fly preventive methods appear to be favored as they cut down on non-productive time and reduce costs in the longer term while drilling in depleted sands as can be seen using the new 3D MUDSYSTTM model.
Replacing ESP and Gas Lift with ESTSP (Electric Submersible Twin Screw Pumps)
Authors: MacNeil David , Dass Pradeep
Published: June 2014

A detailed study and extensive evaluation was done by Talisman Energy to select the best artificial lift solution for the Situche Field in Block 64, Peru. Gas lift, ESP and Hydraulic Lift were studied. However, a New Technology, ESTSP (Electric Submersible Twin Screw Pumps- Multiphase) was selected for these sour, deep and hot wells.
Delivering Consistent Top Quartile Drilling Performance Without Compromise
Authors: Cockram Mark , Christensen Arne Wyller , Thistle Bruce , Boon von Ochssee Willem , Sinet Jean Claude , Hevrøy Frode , Barke Svein Bjarne
Published: June 2014

When the operator embarked on an intermittent 5 well exploration, appraisal and development campaign offshore Norway between 2009 and 2012 using the West Alpha there were many challenges. The rig contract was part of a multi company consortium, the well program was varied, a 3rd generation semi submersible rig was being used and all inclusive operating rates were high at around $1,000,000 per day.

Following and expanding upon the management principles previously employed 1, the lead operator identified an opportunity to leverage the consortium program and develop a strong relationship with the service companies, in particular the rig contractor.

Health, Safety, Security and Environment (HSSE) was a key driver and over 1000 rig days were delivered without a Lost Time Incident (LTI). The lead operator was able to harmonise and standardise procedures used on every well, regardless of who operated the rig. This enabled a much clearer and more consistent message to be delivered to the work environment.

This paper will outline the management process taken by the operator and contractor that enabled the following performance to be delivered:

1000 days LTI free rig operations. Record setting drilling performance with improvements up to 40%. No damage to the environment.

This paper will also describe how the principles have been transferred to other parts of the operators & contractors organisations.
Real-Time Evaluation of Hole Cleaning Conditions Using a Transient Cuttings Transport Model
Authors: Cayeux E. , Mesagan T. , Tanripada S. , Zidan M. , Fjelde K. K.
Published: June 2014

During a drilling operation, real-time analysis of surface and downhole measurements can give indications of poor hole cleaning. However, it is not always intuitive to understand how and where the cuttings are settling in the borehole, because the transportation of cuttings and the formation of cuttings beds are largely influenced by the series of actions performed during the operation. Using a transient cuttings transport model, it is possible to get a continuously updated prognosis of the distribution of cuttings in suspension and in beds along the annulus. This information can be of prime importance for taking decisions to deal with and prevent poor hole cleaning conditions.

A transient cuttings transport model has been obtained by integrating closure laws for cuttings transport into a transient drilling model that accounts for both fluid transport and drill-string mechanics.

This paper presents how this model was used to monitor two different drilling operations in the North Sea: one using conventional drilling and one using MPD (Managed Pressure Drilling). Some unknown parameters within the model (e.g. the size of the cuttings particles) were calibrated in order to obtain a better match with the top side measurements (cuttings flowrate, active pit reduction due to cuttings removal). Using the calibrated model, the prediction of cuttings bed locations were confirmed by actual drilling incidents like pack-offs and overpulls while tripping out of hole.

Based on the calibrated transient cuttings transport model, it is thereby possible to evaluate what adjustments of the drilling parameters are necessary to stop and possibly remove the cuttings beds, therefore giving the drilling team the opportunity to take remedial and preventive actions based on quantitative evaluations, rather than solely upon the intuition and experience of the decision makers.
Use of Electromagnetic Surveys to Monitor Removal of an Oil Field Produced Water Plume, East Poplar Oil Field, Eastern Montana
Authors: Jacobs Michael , Smith Bruce , Tyrrell Christa
Published: June 2014

In 1999 Pioneer Natural Resources (PNR) was notified that a plugged and abandoned well, the Mesa Biere #1-22 (now Pioneer), operated by Mesa Petroleum and plugged in 1986, appeared to have been improperly plugged and had released chloride-rich oilfield brine into the shallow aquifer.

Pioneer Natural Resources voluntarily designed and built a plume capture and remediation system consisting of thirteen "brine", groundwater removal wells, five crude oil recovery wells and a deep, 7,800 foot, USEPA Class V, injection well. The brine remediation system became fully operational in August 2008 and is operating at an average daily rate of 5,100 barrels per day (214,200 gallons/day). As of December 2012 the system has removed 5,402,739 barrels (226,915,038 gallons) of brine contaminated water with an average concentration >20,000 mg/L Chlorides.

An airborne frequency domain helicopter EM survey flown by the USGS in 2004 mapped the subsurface conductivity of the SE part of the Poplar Oil Field. This survey provided a hydrogeologic framework and plume mapping over a large area. In the Biere #1-22 area Pioneer Natural Resource personnel have conducted more detailed ground EM surveys with a loop-loop EM 34XL system with separations of 10, 20, and 40 meters. These surveys were used in conjunction with water well sampling to develop an estimate of the extent of the brine and crude oil plumes in the Mesa Biere #1-22 area.

Traditional monitoring of plume removal efficiencies depends on groundwater sampling of wells within the plume area and related interpretations of the spatial and temporal changes of the plume are restricted to interpolated data between monitor well locations. The usefulness of the EM surveys are that they are inexpensive and easy to conduct and can give useful information over a much more detailed area within the plume. The Biere #-22 survey consists of 237 stations over a 1.03 mi2 grid on 300 ft and 400 ft spacing. The survey is approximately 16 linear miles. A unique aspect of the ground geophysics has been that the repeated EM34XL surveys conducted since system turn-on shows decreases in the area of high subsurface conductivity that correlates with a decrease in the area of the plume geometry.
Remediation of Contaminated Water Using Heterogeneous Catalyst: A Preliminary study
Authors: Asuelimen L. I. , Huddersman K.
Published: June 2014

PAH-contaminated water containing benzo (a) pyrene (Bap) was treated by oxidative catalytic decomposition using a heterogeneous fibrous (polyacrylontrile-PAN) catalyst in a modified Fenton reaction. This attempted to ameliorate the challenges of conventional homogeneous catalytic method using Fenton reagent in soil and groundwater treatment which is limited by natural processes such as pH buffering, iron precipitation, and the need for recovery of iron in the homogeneous catalyst to comply with environmental regulations. For this purpose several bench scale tests were performed, with hydrogen peroxide and modified PAN catalyst. Optimum reaction conditions were investigated by varying H2O2 concentrations, heterogeneous PAN catalyst, contaminant concentration, and pH. BaP concentration was determined using HPLC. The Fenton-like oxidation was efficient at pH 4-5, neutral, and even above neutral, with degradation efficiencies of 84–100%. With the optimization of the working scale for the catalysis, the optimum condition for the degradation of 0.1 mg/L of BaP in water matrices (50 mg/L H2O2, 2g PAN catalyst, pH 4.5, at normal room temperature) could completely break down BaP in 45 minutes. There was no significant difference in activity of the catalyst after using to fresh feed for seven cycles reflecting the stability and reusability of the PAN catalyst, an indication of its potential use in continuous processes. The overall result indicate that oxidative catalytic decomposition using a heterogeneous fibrous (polyacrylontrile-PAN mesh) catalyst would have a promising application to site remediation.
A Hurt-Based Approach to Safety
Authors: Smith R. M. , Jones M. L.
Published: June 2014

This paper describes the Hurt-based Approach to Safety that ExxonMobil’s Upstream Companies use in personnel safety management. Traditionally, ExxonMobil has primarily used industry standards driven by the U.S. Occupational Safety and Health Administration (OSHA) to classify safety events based on the treatment and/or restrictions provided. However, this treatment-based approach has limitations. With intense focus on administrative reporting (i.e., is the incident recordable or not?) and incident escalation management, the approach does not naturally resonate with workforce members to enable desired cultural changes. Also, historical approaches have not included a potential consequence assessment; a critical element in preventing future injuries. Incident classifications are often inconsistent because work restrictions and medical treatments are subject to individual medical provider judgment.

ExxonMobil has created a Hurt-based Approach to mitigate limitations of the treatment-based approach. This paper discusses the history of ExxonMobil’s "Hurt Free" philosophy and explores benefits:natural safety language of humans; protect family, prevent injuriesconsistent description of actual injury severityintegral assessment of potential injury severityresonates with workforce to enable cultural changes based on caring for peoplealignment with Exxon Mobil Corporation’s safety vision of "Nobody Gets Hurt"

These benefits, along with passionate safety leadership and Hurt-based metrics, are critical elements in ExxonMobil Upstream’s safety management systems. While many companies have some of these elements in their programs, it is the combination of all elements that drive ExxonMobil’s Hurt-based Approach. This paper will share ExxonMobil’s expectations of safety leaders and insight into how a Hurt Free philosophy leads to higher levels of understanding and promotes safety leadership throughout the organization. It will describe how a Hurt-based Approach provides a more natural line of sight for assessing incident potential and provides a more natural and caring interaction with injured parties; thereby, creating a more positive personal safety culture. It will describe how potential consequence is determined and how this potential drives the prioritization of resources, incident assessments, work activity focus, etc. It will detail ExxonMobil’s "Mining-the-Diamond" initiative which provides increased focus on high consequence potential work activities that could result in life-altering injuries or death. Trend analysis will be provided to illustrate continuous improvement efforts.