bluuebunny/crossref_metadata_2025 huggingface dataset:
Avoiding Losses in Depleted and Weak Zones by Constantly Strengthening Wellbores
Authors: van Oort Eric , Friedheim Jim , Pierce Toby , Lee John
Published: October 2009

Drilling depleted or weak zones has always been a challenge, but with the aging of fields and the desire to drill to deeper in-field plays, the situation is becoming more exacerbated. The typical problems associated with drilling these types of intervals are lost circulation, stuck pipe and wellbore instability resulting in significant and expensive non-productive time (NPT) and costly remediation operations. Conventional lost circulation remedies (e.g., pumping lost circulation pills and squeezing) have given way to popular wellbore strengthening solutions. Our approach to strengthening, based on beneficial manipulation of fracture propagation pressure and continuous application of specialized wellbore strengthening additives has had tremendous success in reducing downhole mud losses by more than 80% in Gulf of Mexico deepwater operations and dropping the cost of these incidents out of the top 10 contributors to NPT.

This paper focuses on the various theories and approaches to wellbore strengthening and what the available field and literature data actuallysupport. Building upon this, the approach of gaining wellbore fortification through fracture propagation resistance (FPR) enhancement is introduced, for which experimental results, field data and case histories are shared. Central to our application of FPR to drill challenging deepwater production wells is the notion of providing continuous wellbore protection through a novel and unique solids recovery and reintroduction method that allows for drilling with high concentrations of wellbore strengthening materials (WSM) in the drilling fluid.
Effect of Pressure, Temperature, and Solution Gas on Oil Recovery From Surfactant Polymer Floods
Authors: Roshanfekr M. , Johns R. T. , Pope G. , Britton L. , Linnemeyer H. , Britton C. , Vyssotski A.
Published: October 2009

Surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) flooding is of great current interest owing to the need to recover oil left behind after primary and secondary recovery. If designed properly, these enhanced oil recovery processes can give very high oil recoveries. Microemulsion phase behavior plays a central role in process performance and is typically measured by doing salinity scans in glass pipettes at atmospheric pressure and reservoir temperature using dead crude oil from the reservoir of interest. There have been only a few experiments reported in the literature on live oil at reservoir pressure and temperature and the importance of those experimental results are conflicting.

This paper investigates the effect of pressure, temperature, and solution gas on microemulsion phase behavior and its impact on oil recovery. We examine previous data reported in the literature, and report new measurements with live oil to show that the optimum parameters can change significantly. The experiments show that while pressure induces a phase transition from upper microemulsion (Winsor type II+) to lower microemulsion (Winsor type II−), solution gas does the opposite. An increase in pressure decreases the optimum solubilization ratio and shifts the optimum salinity to a larger value. Adding methane to dead oil at constant pressure does the reverse. Thus, these effects are coupled and both must be taken into account. We derive a new thermodynamic model to explain why the logarithm of oil and water solubilization ratios is linear with pressure or inverse temperature. We also use a numerical simulator to show how to design the chemical processes to account for phase behavior shifts with pressure and solution gas to achieve good oil recovery.
Data Assimilation Using the Constrained Ensemble Kalman Filter
Authors: Phale Hemant A. , Oliver Dean S.
Published: October 2009

When the ensemble Kalman filter (EnKF) is used for history matching, the resulting updates to reservoir properties sometimes exceed physical plausible bounds, especially when the problem is highly nonlinear. Problems of this type are often encountered during history matching compositional models using EnKF. In this paper, we illustrate the problem using an example in which the updated molar density of CO2 in some regions is observed to take negative values while molar densities of the remaining components are increased. Standard truncation schemes avoid negative values of molar densities, but do not address the problem of increased molar densities of other components. The results can include a spurious increase in reservoir pressure with a subsequent inability to maintain injection. In this paper, we present a method for constrained EnKF which takes into account the physical constraints on the plausible values of state variables during the data assimilation. The proposed method can be implemented in two different approaches, both of which convert inequality constraints to a small number of equality constraints. The first approach uses Lagrange multipliers to apply the active constraints. In the second approach, the constraints are used as virtual observations for calibrating the model parameters within plausible ranges.

The constrained EnKF method is tested on a 2D compositional model and on a highly heterogeneous 3-phase flow reservoir model. The effect of the constraints on mass conservation are illustrated using a 1D Buckley-Leverett flow example. Results show that the constrained EnKF is able to enforce the nonnegativity constraints on molar densities and bound constraints on saturations (all phase saturations must be between 0 and 1), and achieve a better estimation of reservoir properties than is obtained using only truncation with EnKF.
Effects of Fluids, Frequency and Heterogeneity on Elastic Properties of Carbonate Rocks
Authors: Sharma R. , Adam L. , Prasad M.
Published: October 2009

Understanding factors controlling the elastic behavior of saturated rocks is critical for characterizing carbonate reservoirs. These elastic properties are often mapped using seismic data. Elastic properties, often derived from inversion of seismic data via velocities, form important inputs for reservoir engineering calculations and simulation studies. Normally, in absence of site-specific measurements at reservoir temperature and pressure, empirical models or data from analog formations are used. However, elastic properties of rocks are controlled by variation in saturant type and its dependencies on pressure and temperature, in addition to rock heterogeneity. The characterization of heterogeneities is important for obtaining rock physical parameters and for understanding flow mechanics in carbonate reservoirs using upscaled geological model for reservoir simulation. Broad objective of this study are, 1) Measure the elastic moduli of rocks as they change with saturant and amount of saturations. 2) Calibrate these changes in rock strength, to understand the difference between the static and the dynamic elastic moduli. 3) Investigate effects of frequency-dependence of elastic moduli and effects of its variation on reservoir engineering calculations and simulation studies. Present paper discusses the effects of fluids, frequency and heterogeneity on the elastic properties of carbonate rocks. Their effects on reservoir engineering calculations will be discussed in future communications.

In this study, comparisons are drawn between a set of homogeneous and heterogeneous samples for their varied response to varying saturant, amount of saturation (Sw), frequencies and differential pressures. At ultrasonic frequencies, bulk modulus in the heterogeneous sample varies by 22% from dry to partial (water saturation, Sw = 56%) saturation stage, and by an additional 7% from partial to full saturation, whereas in the homogeneous sample, bulk modulus varies by 27% from dry to partial saturation (Sw = 90%) and by 29% from partial to full saturation. Similarly, the shear modulus in both samples varies by −2% and −12%, respectively from dry to partial saturation, and by 3% and 10%, respectively from partial to full saturation. For another set of homogeneous and heterogeneous samples we measured the bulk and shear modulus as a function of frequency, saturant and differential pressure. We observe that most samples show an increase in bulk and shear modulus with frequency. We also observe weakening and strengthening of the shear modulus from dry or with a light hydrocarbon to fully-brine saturated pore spaces. Investigations were also carried out for finding any possible correlation between the measured permeability and measured velocity in carbonate rocks. We found no definite correlation between permeability and velocity for both homogeneous and heterogeneous samples.
Challenges on Drilling and Completion Operations of Deep Wells in Ultra-Deepwater Zones in the Gulf of Mexico
Authors: Cunha J. C. , Moreira O. , Azevedo G. H. , Pereira B. C. M. , Rocha L. A. S.
Published: October 2009

Currently some of the most challenging wells being drilled by our industry are located in deepwater zones in the GOM. Many of those wells are in water depths of 8,000 ft. or more and several are targeting reservoirs around 30,000 ft. and beyond.

Drilling engineers face many challenges when planning drilling and completion operations for such wells. There are not many rigs available to drill in ultra-deepwater, and even the modern rigs capable of operating in this environment will present limitations ranging from the maximum mud weight possible to be used, due to riser restrictions, to the hook load capability to run very heavy intermediate casings that will easily surpass one million pounds.

The well itself will present many problems including high pressure and high temperature formations, the need of multiple casing strings, unstable formations, hole cleaning, unexpected presence of tar zones, huge layers of salt, the need to underream the well, difficult to do an efficient evaluation program etc.

On the completion side, the challenges can be even more demanding, with the need to complete multiple zones while trying to minimize future expensive workover operations.

This paper presents some practical experiences on dealing with various of the abovementioned problems and also suggestions to make the problems manageable. It might be emphasized that we do not have a perfect solution to all problems and that we are far to have the most efficient solution to drill deep wells located in ultra-deepwater zones in the GOM. However, with daily operational costs reaching one million dollars or more, it is our intention in this paper to discuss the problems, to point out some possible directions, to show some field cases and to open a discussion that might benefit the entire industry.
Assessing the Impact of Microseismic Location Uncertainties On Interpreted Fracture Geometries
Authors: Maxwell Shawn
Published: October 2009

Interpretation of fracture geometry is an important aspect of microseismic monitoring, especially for hydraulic fracture stimulations. The fracture geometry is often inferred directly from the microseismic locations, particularly by using the few events comprising the edges of the cloud of microseismic locations. These few events are frequently used to measure the fracture dimensions of height and length, as well as the width to interpret fracture complexity. In this paper, a synthetic dataset assuming different location uncertainties is constructed, to illustrate how location errors relate to uncertainties in the fracture dimensions. If the edges or extremities of the microseismic clouds are used to interpret the fracture extents, the synthetic data demonstrate that these locations are potentially statistical outliers of the microseismic uncertainties. Therefore, the extremities are shown to be biased towards measuring larger fracture dimensions, and potentially misinterpretation of fracture complexity associated with mislocated events. A technique termed compression is introduced which considers the probability density function to interpret the statistical spatial scatter of the microseisms, to enable an interpretation of the fracture dimensions ‘compressed’ away from the extremities of the cloud. The synthetic data is used to validate the technique, demonstrating that the resulting fracture geometries are more accurate and are less biased by the location uncertainty. The compression technique was applied to a hydraulic fracture image, for a dataset which was processed using automatic data processing and then reprocessed with a more accurate algorithm. For both the automatically processed and the refined locations, the compression technique results are similar, confirming the technique is relatively insensitive to the location errors. The refined image was sufficiently accurate to identify two discrete structures in the image.
Repeated Judgment Elicitation: Tapping the Wisdom of Crowds in Individuals
Authors: Welsh M. B. , Begg S. H.
Published: October 2009

It is commonly recognised that the Wisdom of Crowds [1] enables a group of people with limited knowledge to make, on average, very accurate estimates. This process underlies the success of prediction markets [2], which are used to accurately predict outcomes as disparate as elections and box office takings. In the O&G industry, however, there are clear limits on the number of people who can be canvassed for their opinions. Not only are there a limited number of people with sufficient knowledge to make any estimate at all for a particular problem but confidentiality restricts this further. Recent psychological research, however, has demonstrated benefits of repeated individual judgments – asking the same person to repeatedly estimate a parameter. We critically review individual, repeated-elicitation techniques currently in use and describe a method that avoids many of the problems with these – More-Or-Less Elicitation (MOLE) [3].

The MOLE is compared with alternate, single- and repeated-judgments elicitation methods, yielding superior accuracy and calibration to any of the alternate techniques. Its estimates explain an additional 20% of the variance in the parameter of interest over its nearest rival and less than 9% of its elicited ranges did not contain the true value when expected to. We argue that, for the O&G industry, repeated individual judgments have the potential to greatly improve the accuracy and calibration of estimates and, further, that the MOLE harnesses the benefits of repeated judgments while avoiding common problems such as repetition of answers and confirmation bias.

This paper reviews the latest research on repeated judgments in elicitation and demonstrates the benefits of repeated, individual judgments for elicited values. The MOLE, which takes advantage of these benefits, is simple and easily transferable to most elicitation domains, enabling its benefits to apply throughout the industry.
A Systems Engineering Approach to Change Management that Overcomes the Barriers to User Acceptance
Authors: Campbell Michael
Published: October 2009

Definitions are important to understanding the message of this paper. Therefore, let's begin with the two key definitions. At a high level a system is defined as the combination of related parts organized into a complex whole1. And change management is defined as a structured approach to transitioning individuals, teams, and organizations from the current state to a desired future state2. Taken together, these definitions should dispel the notion that moving people from the status quo to a new way of working with digital technology will not be either easy or quick. As we have all learned, it is complicated and sometimes, unpleasant.

As an illustration, Douglas K. Smith gives us words of wisdom as we try to get users aligned with the new technology. He says, "You can encourage, cajole, demand, reward, support, flatter, educate, reassure, inspire and threaten, but until enough people, including you risk some combination of ChoiceActionReflectionRepetition

Neither individual nor organizational change occurs.3
Strategies for Acquiring and Integrating Petrophysical Data for Reservoir Evaluation
Authors: Amabeoku Maclean O. , Kersey David G. , BinNasser Rami H. , Mohammadi Hisham H.
Published: October 2009

The use of key wells to improve formation evaluation programs is well established as this method has been proven to improve petrophysical accuracy. In the key wells, extensive logging, coring and fluid sampling programs provide the data used to develop better predictive models for water saturation, lithology, porosity, and permeability. To be effective, key well programs must obtain representative special core (SCAL) data from all cored facies, but this often requires high-density sampling, which may not be cost effective. This paper presents a strategy to meet technical and business objectives by selecting optimum number of samples required to provide the data needed to develop improved petrophysical models.

A case study is provided showing the development of an optimum SCAL sampling strategy for a carbonate reservoir. This example highlights how an optimum sampling program for capillary pressure, electrical properties and relative permeability tests leads to enhanced formation evaluation. The case study demonstrates how effective sampling strategies improve determination of water saturation and permeability. It also shows how relative permeability data from a carbonate reservoir may not be directly usable for reservoir simulation if all rock types are not sampled. To represent all rock types, porosity and permeability were initially used to develop hydraulic units. Next, geologic descriptions, which incorporate thin section petrography, X-ray diffraction, and scanning electron microscopy, were used to characterize the reservoir rock in terms of geological facies. X-ray computerized tomography (CT scanning) was used to determine core plug heterogeneity, especially vugginess and mineralogical changes not visible on inspection. Lastly, mercury porosimetry was used to group core plugs of the same rock type based on similarity in pore size distribution. These composited core plugs were then subjected to relative permeability measurements at reservoir conditions.

Using the data from this study, core-calibrated saturation and permeability profiles were developed for all rock types. In addition, an analytical relative permeability model for direct input into flow simulators was developed and validated. This model is easy to use and can be modified quite easily during reservoir simulation by changing some predetermined parameters in the model. This should reduce the time and expense of history matching. The model incorporates the scatter in relative permeability data that is usually encountered in laboratory measurements.
Can Sand Screen Failures be Prevented in Gravel Packed Cased Hole Completions?
Authors: Gillespie George , Jones Colin
Published: October 2009

Sand control screens must effectively retain the gravel pack and formation sand, and provide a conduit for fluids to flow into a cased hole producing well. A failure may occur while completing the well, or at some time during the well's operating life. The root cause of the screen failure is often difficult to determine with absolute accuracy. Often, it is determined that screen failure occurs due to a combination of plugging and erosion resulting in the loss of sand control.

A comprehensive test program was undertaken to evaluate erosion rates of different screen types of cased hole completions completed with wire wrap, prepacked screens, metal mesh, or compliant sand screens. The purpose was to determine whether any screen type had a marked advantage to resist erosion during the gravel packing process. Tests were conducted at high velocities to simulate the end of the gravel packing process to determine erosion of the screen in a reasonable time scale.

To evaluate the expected screen's service life while the well is in production, configurations of each screen type were installed in a test fixture, and several tests were conducted at different velocities and sand concentrations. Special ports were used to simulate producing through a cased hole perforation tunnel.

The sand was sized to pass through the screen with minimal plugging, which would simulate fines production over time in a producing well. The specific wear rates and percent of rate loss were determined for each test. Micro photos were used in the analysis of the wear patterns, along with pre and post test measurements of the wire wrap slots or metal mesh pore sizes.

This paper will describe the test methods used, the test results and lessons learned, and will describe a model that can be used to predict a screen's service life for cased hole completions based on a given set of well conditions.
Improving Allocation and Hydrocarbon Accounting Accuracy and Automating Associated KPI's
Authors: Cramer Ron , Schotanus Dave , Colbeck Nick
Published: October 2009

In the oil industry it is necessary to reconcile fiscally measured hydrocarbon production with estimated production from the associated wells. This process is known as "allocation" and is important for a number of reasons including accounting for field production to owners/governments, field surveillance and volumetric input to reservoir simulators.

Traditionally allocation is performed on a monthly basis, reconciling the "less accurate" sum of the well tests adjusted by well uptimes with the "more accurate" fiscal measurements. This process is subject to a number of inherent inaccuracies including less than perfect well tests, lack of knowledge of precisely when the wells were interrupted, unknown well flow changes and how to effectively allocate the difference between fiscal and well test measurements.

Ineffective allocation can lead to financial consequences due to inaccuracies in volumes allocated between multi-various owners and various tax regimes. Inaccuracies can also feed through to reservoir simulators which may be used in corresponding decision making processes such as where to drill the next well. These inaccuracies are generally compounded with time, as allocation is performed month after month over the field life cycle.

Associated with hydrocarbon accounting are some Key Performance Indicators (KPI's) such as well daily production and deferment rates.

The purpose of this paper is to describe Shell experiences in improving allocation accuracy and automatic KPI reporting through more effective use of available production data and by using a continuous, rather than a discontinuous hydrocarbon accounting process.
Simplification of Coupled Reservoir and Facility Modelling to Facilitate Efficient Decision-Making: An Example of a Miscible Sour Gas Flood for Enhanced Oil Recovery
Authors: van Berkel J. T. , Hassan A. A. , Haynes B. , Woodhead T. J.
Published: October 2009

The Shell integrated modelling methodology places a strong emphasis on achieving the appropriate focus at each step in the business cycle. In particular, the net is cast wide at the project feasibility stage requiring a large number of development opportunities to be evaluated using simple or coarse modelling. Where the development planning requires an understanding of critical interactions between the reservoir and the surface due to the presence of a complex facility network, an Integrated Production Systems Model (IPSM) is an essential tool. To provide for an efficient and flexible evaluation of a range of development options it is crucial to simplify where possible, with a suitable validation step to ensure that the simplifications have not lost essential detail.

To illustrate the methodology, a field case of the miscible gas flood of several different reservoirs produced through a common facility is presented. Results from an IPSM with a simplified facility model were validated against a more detailed facility model in Unisim. The simplified facility model has sufficient details to closely match the predictions from the detailed model and is easy to change when defining alternative concepts or scenarios. This methodology allows for a rapid and robust evaluation of various field development concepts using an integrated reservoir/facility model.
Drill-Bit Metamorphism: Recognition and Impact on Show Evaluation
Authors: Wenger Lloyd M. , Pottorf Robert J. , Macleod Gordon , Otten Glenn , Dreyfus Sebastien , Justwan Holger , Wood Emily Sekula
Published: October 2009

With petroleum exploration and development progressing into deeper and more challenging environments, drilling technology has provided the means to effectively and safely reach and complete desired targets. Approaches such as turbo-drilling with polycrystalline-diamond compact (PDC) bits or diamond-impregnated bits increase penetration rates, lessen drill-bit changes, and are more easily steered in directional drilling, but also generate artifacts that may hinder recognition of indigenous hydrocarbons and interfere with geochemical interpretations. The higher bit speeds with turbo-drilling compared to rotary drilling (e.g., ~1000 vs. 300 rpm, respectively) often generate additional heat that may essentially fuse rock cuttings with drilling mud, thermally crack oil-based drilling fluids, and produce both hydrocarbon and non-hydrocarbon artifacts.

Bit-generated rock textures and pulverized drill cuttings, mixed with drilling mud cause difficulty in evaluation of lithology, age, and shows. The recognition of indigenous vs. artifact products is crucial to determining the presence and characteristics of hydrocarbons encountered in the well bore. These can be distinguished through analyses of mud gas and fluid-inclusion volatiles (FIV) analyses of drill cuttings.

Analyses of mud gases show that gases typically not found in natural gases are generated during drill-bit metamorphism (DBM) including CO, ethene, and propene. Gases are rich in methane and C2-C4+ hydrocarbon gas components and may include H2S, CO2 and carbonyl sulfide (COS). Laboratory experiments suggest that thermal cracking of oil-based drilling mud can be the major contributor to these gases. Cracking of base oil alone generated wet gas with little CO2 and no H2S, while cracking of base oil in drilling mud generated wet gas with abundant CO2 and H2S. Drilling mud additive components such as lignosulfonate are likely sources of the generated CO2 and H2S. Recognition of DBM is crucial to effective drilling operations and evaluation of indigenous hydrocarbons.
Evaluating the Movement of Injected Gas and Identifying Bypassed Condensate in the Oso Field, Offshore Nigeria
Authors: Sumpter L. T. , Gunther M. , Kerscher I. M. , Leininger S. C. , Wudiri B.
Published: October 2009

The Oso field is a faulted monocline that has been producing condensate from two shallow marine/fluvial reservoirs since 1992. Original pressure data indicates the two reservoirs are connected in the condensate leg but not in the water leg. This relationship requires seal at some points of cross-fault reservoir juxtaposition and leak at others. The original aquifer pressure was much lower in the younger reservoir, allowing the original condensate-water contact to be over 1,100 feet deeper than the contact in the older reservoir. Neither reservoir had an original gas cap, but both have received gas injection.

The objective of this study was to gain a qualitative understanding of the dynamic behavior of the reservoirs and faults in order to identify the key elements of the reservoir architecture prior to building a geologic model and progressing to reservoir simulation. Specifically, we attempted to evaluate cross-fault communication between the two reservoirs, cross-fault communication within the same reservoir, the significance of interbedded shales in the relatively thick older reservoir, advancement of the aquifer, the movement of injected gas, and the potential for bypassed condensate. The interpretation of available seismic data provided a coarse framework for this study, but the most significant insights came from the evaluation of wireline log, pressure, and production data from more than 70 wells drilled at various stages of the field's history.

Pressure data from wells drilled after production start-up combined with observations of the distribution of injected gas allowed us to conclude that there is significant variability in fault transmissibility among different faults and along the length of a single fault or fault system. This variability may be explained, in part, by changes in fault gouge composition associated with net-to-gross variation in the reservoir. Observed gas movement (or lack of movement) across some faults has very specific implications for the location and risking of in-fill wells targeting bypassed condensate. Interbedded shales within the thick (~750 feet) older reservoir have a significant impact on the sweep efficiency of injected gas and the location of bypassed condensate. The interbedded shales could not have been mapped from seismic data or with the limited well control available in the initial stages of development, but with the additional well data acquired in subsequent in-fill drilling programs we were able to map them for this study. Mapping of the shales allowed us to interpret the distribution of bypassed condensate encountered by in-fill drilling, demonstrating the importance of maturing our mapping as the field matures and considering both geologic and reservoir engineering data and concepts in the mapping process.
Training the Next Generation of Project Leaders
Authors: Massingill Robert D.
Published: October 2009

ExxonMobil1 Project Management resource needs require the successful assimilation, development, and retention of young talent. This paper will highlight key components, examples of methods used, and recent lessons learned at ExxonMobil Development Company (EMDC) to ensure our employees develop the Global Project Management skills required for the project needs of tomorrow.

Specifically, two key components of our career development program will be discussed. A primary way to prepare the next generation of project leaders is to ensure they gain a core set of competencies in their first three years via a combination of "on-the-job" training experiences and traditional training courses. New project management engineers are provided a focused list of experiences that they are to gain either through on-the-job experience, classroom training, or individual learning experiences (e.g. interviews, computer-based training, or technical coaching). Classroom training in specifically designed company courses ensure our future project managers have the skills and knowledge of ExxonMobil methods / processes to be successful in meeting all project goals. These courses include both technical and individual effectiveness topics. Assignments for the engineers are selected to facilitate the development of Basic Level and Competent Level Project Management skills. All activities are defined and tracked with an award given for the achievement of these Early Competency Milestones.

Mentorship is the second key component of developing the next generation of project leaders. Mentoring plays an important role in knowledge transfer and wisdom sharing – the ability to expedite the acquisition of experience and skills without having engineers "get old" doing the work is vital. The mentoring program in EMDC assigns each professional with a mentor to help guide him / her both technically and from a career management perspective. Additional methods of mentoring to share experiences and knowledge are utilized. A program called "Ongoing Wisdom and Learning" (OWL) pairs senior project professionals and senior technical professionals with groups of less experienced engineers in an open and candid discussion of their career. OWL topics range from technical subjects to project leadership to career guidance and has proven to be a very popular knowledge transfer technique.

The ultimate method to acquire key project management skills is to include an assignment on a multi-national project. Several projects have "development" positions built into the staffing plans and funding program. These projects combine the two key aspects of the development program: "on-the-job" experiences and strong mentorship.

With a structured and focused approach to the development and preparation of our young talent, ExxonMobil feels it will be able to continue to meet the resource needs for energy projects around the world.
Multivariable Control for Upstream Gas Processing
Authors: Vines Michael
Published: October 2009

A project successfully implemented Multivariable Control (MVC) on three upstream gas processing plants at Longford, Victoria (Australia). This poster includes discussion of MVC theory, field data, plant models, results and conclusions.This poster is applicable to control system design or optimization for upstream production facilities. The project employed MVC on both Turbo-Expander and Lean oil type gas processing trains. The technology, however, is relevant to all constrained oil and gas production facilities. Constraints mitigated by this technology included capacity, product specifications, liquids recovery and equipment imposed limitations.The project enhanced recovery of LPG from natural gas in the three gas plants. The MVC technology created plant models of up to one hundred variables to effectively automate the plants. All plants models had a prediction horizon of two hours and a running frequency of one minute. Economic optimization of the plant uses both linear and quadratic programming. Variables controlled included continuous, intermittent and ramp variables. The MVC project exceeded expectations. The gas plants now recover more LPG from sales gas and the plants" capacity increased. Plant stability, alarm and operator intervention frequencies also improved. Looking forward, there are further attractive opportunities for MVC in Esso's upstream facilities. There are currently plans to apply MVC technology to three light ends fractionation trains at Long Island Point on Westernport Bay (Australia).The Longford Gas Processing facilities are owned by Esso Australia and BHP Billiton in a 50:50 joint venture arrangement. The Operator, Esso Australia Pty Ltd is a subsidiary of the Exxon Mobil Corporation.
Practices Implemented to Achieve Record Performance in Narrow-Margin Drilling in Bass Strait Extended Reach
Authors: Kilroy Dale D. , Dupriest Fred E.
Published: October 2009

This paper discusses the successful application of the operator's drilling performance management process in the Australia Snapper / Moonfish platform drilling program. Snapper performance has historically been limited by shale instability, collapsing coal seams, lost returns, and other narrow margin drilling challenges. The design and execution practices implemented achieved record performance while simultaneously addressing the borehole behaviors that prevented the previous extended reach drilling (ERD) campaign from fully developing significant Moonfish resources.

The operator's performance management process ensures both bit and non-bit limiters, such as borehole instability, are addressed with equal rigor, technology, and workflow. Issues that were previously viewed as trouble costs are treated as drilling performance limiters so solutions are pursued that both eliminate the trouble time and increase footage per day. The performance and borehole management practices implemented by the multifunctional team included:

– Wellbore profile optimization to maximize shale and coal stability; – Specialized rig equipment and operational practices for equivalent circulating density (ECD) management; – Unique coal drilling practices to improve borehole stability; – Application of specialized hole cleaning equipment and surveillance; – Bit and bottomhole assembly (BHA) design to manage borehole quality while maximizing rate of penetration (ROP) and tool life; – Contingency planning for execution flexibility to respond to borehole limiters; – Office and field team training and alignment for flawless execution.

The Moonfish M33a and Moonfish A26a extended reach wells were drilled to total depths of 20,341 and 21,180 ft, respectively. Both wells were completed under budget and are among the highest oil producers in the Bass Strait. The performance management process ensured that the borehole behaviors which had lowered the results of previous wells were addressed, while simultaneously achieving record setting performance.

Interests in the Snapper and Moonfish fields are held by Esso Australia and BHP Billiton in a 50:50 joint venture arrangement. Esso Australia Pty Ltd provides services to the joint venture and is a subsidiary of the Exxon Mobil Corporation.
Coupled Completion and Reservoir Simulation Technology for Well Performance Optimization
Authors: Grubert Marcel A. , Wan Jing , Ghai Sartaj S. , Livescu Silviu , Brown William P. , Long Ted A.
Published: October 2009

Ensuring long-term optimum completion performance is important for the economic development of any field. As fields are now developed with fewer wells and in more technically challenging environments, new technologies are required to provide guidance and quantify the impact of completion design. This paper presents a new methodology and workflow to optimize long-term well performance by coupling ExxonMobil's reservoir simulator and a detailed completions hydraulics simulator which models reservoir, wellbore tubing and wellbore annulus flow simultaneously. A case study indicates that unique completions opportunities are captured by using the modeling capabilities.

Completion strategies frequently include provisions to 1) maintain a uniform production profile along the wellbore, 2) manage future risks (early water or gas breakthrough) and mitigate the potential for sand production, and 3) improve reservoir recovery. In order to achieve these strategies, a proposed coupled well and reservoir simulation provides not only detailed information on the tubing and annulus flow and associated pressure drops in and throughout all completion types, but also the impact of completions on short and long term reservoir flow and recovery. The significance of this new coupled approach is its ability to capture both flow dynamics through various completion options and reservoir performance.
Application of Continuous Improvement Methods to the Petroleum Upstream Business
Authors: McCall John , Smart Peggy , McNeil Dale
Published: October 2009

Imperial Oil has a strong history and culture of continuous improvement (CI). Historically the benefits seen from CI were less in the upstream business than in the downstream and other areas with resulting skepticism on the method validity for the resources business. In recent years, Imperial Oil has tested a more aggressive application of CI methods in upstream operations with positive results.

The technical methods for CI are broadly known. The approach taken at Imperial Oil Resources (IOR) was to develop the management techniques for CI initiatives. A project philosophy was used and processes were established for initiating, staffing, tracking and closing each initiative. Dedicated CI personnel were added and trained. Expectations were set for the delivery of results. Hindsight reviews have been established to verify the success of each effort.

The toolset used was expanded beyond the published Lean and Six Sigma methodologies. Methods were added, such as those used for improving the profitability of a target business segment and for assessing reliability issues that have been proven in other business functions. An examination of the challenges encountered by CI specialists indicated the need for additional training in leading and influencing others. Project teams have also been assembled with experts external to Imperial Oil's upstream business using company staff from other business lines. Skills have been developed in engaging suppliers, contractors and regulatory agencies in IOR's projects.

Positive results have been realized in a broad array of areas. Maintenance improvements, general operating cost reductions, energy efficiencies, environmental impact and volume improvements have been achieved in existing conventional and unconventional operations at surface facilities, plants, well servicing and support functions. In the second year of operation, the CI program at IOR implemented projects that will provide over 30 million dollars per year in ongoing financial benefits. In addition significant benefits were realized from the application of these methods to reduce operating costs in a planned oil sands mining project. Active projects are expanding efforts into other areas such as drilling.
A Technique for Averaging Matrix-Fracture Fluid Transfer Rates for Multiple Displacement Processes in a Naturally Fractured Reservoir Model
Authors: Eccles T. K.
Published: October 2009

A common method of modeling naturally fractured reservoirs is a dual porosity approach that uses two identical grids superimposed on each other. Porosity in one grid represents pore space within matrix rock. In the other it represents fracture space between blocks of matrix rock. Fluid transfer rates between corresponding fracture and matrix grid nodes due to capillary pressure and gravity effects are determined from the results of independent simulations that model displacement of fluids in the matrix by fluids from the fracture.

This paper presents details of a technique for averaging results of these independent simulations when multiple displacement processes are expected in the reservoir. Motivation came from the need to model a naturally fractured field in which water was first injected below the oil zone in a peripheral waterflood. At the end of the waterflood, gas was injected at the top of the oil zone as the second part of a double displacement process. Fluids in the matrix rock were expected to be displaced by fluids from the fracture network with the following processes: water displacing oil, oil displacing water, and gas displacing oil and water.
Successful Subsea Interventions in North Sea Beryl Field
Authors: Lonnes Steve , Williams Bruce , Burleson Sheldon
Published: October 2009

Effective management of subsea assets requires diligent focus on key performance areas such as productivity improvement, hydrocarbon recovery efficiency, production preservation, and well integrity. Common to all of these key areas is a need to perform periodic interventions on the asset's subsea wells to carry out performance-critical work, e.g., well servicing/repair, production enhancement, reserve additions, and surveillance. Well intervention services on subsea wells have been conventionally performed using large and expensive Mobile Offshore Drilling Units (MODUs). In the North Sea, ship-based light well intervention (LWI) services offer a lower cost solution to conventional MODU based intervention services by using dynamic positioning over the wells and deploying a subsea BOP stack plus fixed-length lubricator that connects as a self-contained unit to the subsea tree. Tools are conveyed on wireline/slickline from the vessel through the open sea into the self-contained subsea lubricator/BOP stack.

While these LWI services are lower cost, there are more physical and functional limitations that can result in additional technical challenges. One such challenge was encountered when ExxonMobil was evaluating its first LWI on a 5-1/8" × 2" spool/horizontal tree. The target was to pressure test the full TRT/BOP/lubricator stack-up, deploy the pressure tested system as a single unit, and establish hydraulic control of the tree such that separate emergency disconnect devices were not required beyond what was integral to the vessel's proven BOP/lubricator equipment. To achieve this end, ExxonMobil performed quantitative risk analysis on three viable equipment stack-up configurations to determine the safest and lowest cost approach for connecting to its spool/horizontal tree while honoring the 44 ton lifting limits of the particular LWI vessel. The results of this analysis showed that the equipment configuration that was statistically the safest was also the simplest and lowest cost option. Based on the analysis, ExxonMobil modified an 18-3/4" hub style connector for connection between the subsea tree and the vessel's BOP/lubricator and developed a flying stab plate deployment approach, with umbilical slack management, to facilitate stabplate make-up for hydraulic tree control from the vessel. The flying stabplate umbilical leveraged the vessel's BOP/lubricator emergency disconnect to further simplify the system and improve safety. The system has been used twice since development and both deployments were successful.
The Memory Experiences and Dreams Questionnaire (MED-Q): A Validated Measure of Dream Remembering
Authors: Horton Caroline L. , Conway Martin A.
Published: October 2009

Dream recall has been investigated via various means, often relying upon self-report judgments. Such methods, as well as individual differences and cognitive correlates of dream recall, rarely acknowledge models, theory, or empirical work concerning waking memory. Study 1 presents the development and psychometric validation of the Memory Experiences and Dreaming Questionnaire (MED-Q)—a 30-item measure of autobiographical and dream memory sensations incorporating items on dreaming, sensory experiences, and autobiographical remembering behaviors. It produces a single score and can be broken down into its constituent factors: “awareness of dreaming,” “daydreaming,” “dream sensations upon waking,” “déjà-states,” “comprehensibility of dream content,” and “senses.” Study 2 demonstrates the validity of the MED-Q as compared with dream report indices of dream detail. The MED-Q measures the extent to which a person engages with their dream memories through both frequency and subjective characteristic ratings. It is therefore novel in emphasizing the context of autobiographical memory for dreaming.
Spatial Imagery: A New Measure of the Visualization Factor
Authors: Campos Alfredo
Published: October 2009

This study proposes a new measure of spatial ability based on the measure of the visualization factor. I assessed the reliability and the validity of the Measure of the Ability to Form Spatial Mental Imagery (MASMI). The test was designed consisting of an unfolded cube that the subjects had to mentally reassemble before replying to 23 questions related to the cube. Each question had 4 multiple choices, 2 true and 2 false, the total score being the sum of all the correct answers and then subtracting the wrong responses. The sample consisted of 138 undergraduate psychology students, with a mean age of 20.1 years. I obtained a Cronbach's α of .93. The MASMI was correlated to different imagery measures—i.e., imagery questionnaires and spatial tests. The results reveal that the new test provides a good measure for the assessment of imagery ability. Fresh lines of research are proposed in relation to these tests.
Sleep Patterns, Personality, and Subjective Anomalous Experiences
Authors: Simmonds-Moore Christine
Published: October 2009

An opportunity sample comprising 281 participants completed a battery of questionnaires, which included questions on sleep, the Anomalous Experience Inventory [1], the STA scale (for measurement of positive schizotypy) [2], the Complex Partial Epileptic-like signs scale of the Personal Philosophy Inventory [3], Hartmann's Short Boundary Questionnaire (BQ) [4], and the revised Transliminality scale [5]. There was no difference between long and short sleepers on anomalous experiences. All personality variables correlated positively with anomalous experiences. A significant difference was found between short and average and average and long sleepers on positive schizotypy. No other personality variables related to sleep variables. A regression path analysis indicated that the strongest predictors of anomalous experiences were personality factors (in particular, Transliminality and Temporal lobe lability). Reduced sleep quality was also a direct predictor. Reduced sleep need was found to be an indirect predictor of anomalous experiences. Findings support the idea that anomalous experiences could be associated with reduced sleep quality, but not sleep length. The relationship between personality and anomalous experiences may be partially modulated by sleep variables. Further research is needed in this area.