bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of intraoperative constant rate infusion of lidocaine on short-term survival of dogs with septic peritonitis: 75 cases (2007–2011)
Authors: Bellini Luca , Seymour Christopher J.
Published: February 2016

OBJECTIVE To investigate whether intraoperative administration of a lidocaine infusion to dogs with septic peritonitis was associated with short-term (48 hours) survival after surgery.

DESIGN Retrospective case series.

ANIMALS 75 dogs with septic peritonitis.

PROCEDURES Medical records of dogs with septic peritonitis that underwent laparotomy between January 2007 and December 2011 at the Royal Veterinary College were reviewed. Select variables during the preoperative, intraoperative, and postoperative periods and short-term survival after surgery were compared between dogs that received an opioid only (group O; n = 33) and dogs that received lidocaine (50 μg/kg/min [22.7 μg/kg/min], IV; group L; 42) in addition to an opioid during surgery.

RESULTS The proportion of dogs that survived for 48 hours after surgery was significantly greater for group L (35/42) than for group O (20/33). Intraoperative infusion of lidocaine increased the odds of short-term survival (OR, 8.77; 95% CI, 1.94 to 39.57). No significant differences were observed between the 2 treatment groups for variables assessed during the preoperative and postoperative periods. During the intraoperative period, more dogs in group L received an IV bolus of a synthetic colloid than did dogs in group O, but the number of IV boluses administered was not associated with short-term survival.

CONCLUSIONS AND CLINICAL RELEVANCE Results indicated that IV infusion of lidocaine might improve the short-term survival of dogs with septic peritonitis. Prospective clinical trials are necessary to determine the efficacy of lidocaine as a supportive treatment for dogs with septic peritonitis.
Fear-Avoidance Beliefs and Chronic Pain
Authors: Gatchel Robert J. , Neblett Randy , Kishino Nancy , Ray Christopher T.
Published: February 2016

Fear-avoidance (FA) beliefs are significantly associated with the experience of pain, especially when the pain becomes chronic in nature. The anticipated threat of intense pain will often result in the constant vigilance and monitoring of pain sensations, which, in turn, can cause even low-intensity sensations of pain to become unbearable for the person. Just the anticipation of increased pain or reinjury can further stimulate avoidance behaviors. A vicious cycle may develop, in which fears of increased pain or reinjury contribute to the avoidance of many activities, leading to inactivity and, ultimately, to greater disability. Anyone who assesses and treats pain-related disability should also be prepared to assess and treat pain-related FA.

J Orthop Sports Phys Ther 2016;46(2):38–43. doi:10.2519/jospt.2016.0601
A Laboratory Study Investigating Methods for Improving Oil Recovery in Carbonates
Authors: Webb Kevin John , Black Clifford James J. , Tjetland Gunnar
Published: February 2016

Previous studies have shown that waterflood recovery is dependent on the composition of injection brine in clastic reservoirs.

Some researchers have also shown that oil recovery from carbonates is dependent on the ionic composition of the injection water. These studies have however been generated at laboratory conditions which are not representative of the reservoir, and therefore it is uncertain whether these IOR benefits are applicable to actual reservoir waterflood oil recovery.

A reservoir condition coreflood study was therefore performed on core from a North Sea carbonate field (Valhall) to determine whether the recovery benefits seen in reduced condition experiments, were also obtained from full reservoir condition tests, using live crude oil and brine. In these reservoir condition tests, two reservoir core plugs were selected from the same reservoir layer and were similar in reservoir properties so that comparisons could be drawn between the experiments. Samples were prepared to give initial water saturations which were uniformly distributed and volumetrically matched to the height above the oil water contact of the samples in the reservoirs. The initial water saturation composition was based upon the simulated formation brine composition of the field. The plugs were then aged in live crude oil to restore wettability. Imbibition capillary pressure tests were then performed at full reservoir conditions, with live oil and brine, using the semi dynamic method. The first experiment utilised a simulated formation water and the second test utilised a simulated sea water, respectively, as the displacing water.

The resultant data showed that the sea water used in the capillary pressure test modified the wettability of the carbonate system, changing the wettability of the rock to a more water wet state. This was indicated by comparing the saturation change in the spontaneous imbibition phase of the test between simulated formation and sea waters.
Global Attraction and Local Development of the E&P Professional
Authors: Wilson D.
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

The global Oil and Gas industry that not so long ago had the pick of the best graduates from the best Universities now finds itself struggling to convince young people that it is the place to be in the 21st century. Coupled with a demand from the existing workforce to have more influence over their development and career direction, this led Shell EP International to detail its offering in the People in EP (eXp) Framework.

eXp is more than an employee value proposition, it is a transparent set of linked global processes that clearly define the role of both company and individual in the development process. It specifies people commitments, standards, processes and products. The design was the outcome of several years work aimed at understanding the needs of today's professional, it is accessible at the Desktop at anytime in any time zone and is used for staff engagement.

To review all the processes in the time available would not be possible. This proposal will focus, therefore, on recruitment, skill pool management and professional learning.

A subject such as this is best served visually. It would therefore be our preference, should the Programme Committee agree, to make a Power Point presentation of the eXp framework to the Conference.

Key elements of that presentation would be:An overview and explanation of the FrameworkGlobal RecruitmentDrive to recruit from non-traditional areasGraduate Assessment CentresRecruitment of experienced professionalsSkill Pool ManagementSkill Pool structure and ownershipManaged Open ResourcingCompetence Based DevelopmentJob Experience NavigatorLeadership Talent PipelineProfessional LearningShell Open University, a single learning portalLearning deliveryBlended LearningWork Place Learning

Shell works in partnership with Governments and National Oil and Gas Companies in many parts of the world, no more so than in the Middle Eastregion. The tools and processes described are available to our joint venture companies to ensure that regional staff are developed to the highest professional standards including work assignments in many of our ventures worldwide.
Catastrophic Failure Elimination by Implementing Predictive Maintenance Technologies at Sumatra Light North Operations
Authors: Said D. , Darmawan T.
Published: February 2016

Predictive Maintenance (PdM) assesses the equipment's health through diagnostics testings and / or on line monitoring. The machine's condition may be inspected and monitored using continuous or intermittent parameter measurement intervals. PdM techniques can detect trend changes in running conditions that could lead to catastrophic failures. They are used to identify or predict the early indication of failures, which in turn can provide greater lead-time for developing suitable action plans prior to the failure, resulting in reduced unscheduled down time and prevent any possible catastrophic failures.

There are many known technologies for PdM. The types of Techniques that have been implemented at Sumatra Light North Operations (SLN) - Indonesia are: Vibration Analysis;Thermography Inspection;Reciprocating Tools Analysis;Lubricant Analysis;Ultra-Sonic Flow Rate Testing.

This paper will share five case studies of PdM in SLN operations. By implementing PdM technologies as demonstrated by these examples, the opportunity of having the risk of catastrophic failure will be minimized. This can be achieved by taking actions in advanced based on the information of equipment conditions discovered through data collection and analysis.

Introduction

The function of maintenance is to sustain the integrity of physical assets of the company over their planned life by repairing, modifying or replacing them as necessary within the agreed budget for supporting the attainment of the company goals that are to optimize the oil and gas productions. In doing so the life cycle costs (LCC) and its influencing factors should be the basis for decision making in putting any maintenance strategy in place. Those LCC factors include acquisition costs, running (operation, maintenance and energy) costs, and abandonment costs. Focusing on maintenance costs themselves, it involves cost factors such as: labor, materials, spare part ordering and holding costs, tools and equipment, engineering support costs, contractors and other overhead costs. With the above factors, several maintenance strategies can be selected based on the production targets, asset criticality assessment, risk based, or others that can be different from company to company depending on company goal.
Challenges in Seismic Data Acquisition and Processing - The Petronas Experience
Authors: Low C.F. , Ghosh D.P.
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

PETRONAS has been actively acquiring large volumes of seismic data in varied and difficult terrain to support its worldwide exploration, development and production activities. In the Malay Basin of Malaysia, the challenge begins with imaging complex stratigraphic reservoirs that are often below conventional seismic resolution. The Malay Basin being a fairly matured exploration & production province also poses another challenge, i.e. acquiring high quality seismic data around platforms and other obstructions.

In Vietnam, our team was tasked with imaging complex fractured basement reservoirs under an overburden of clastic and volcanic rocks while in Indonesia, obtaining high quality, contiguous data over a land-marine interface required four different acquisition techniques and special processing workflows. In offshore Mozambique, East Africa where strong currents prevail in a N-S direction, binning and stacking methodology was used to ensure a thorough reflection of the subsurface. The high elevation changes in the mountainous region of Yemen called for a special array design, dual elevation and hybridstatic routines, while under the dunes of Algeria, the low relief structures needed proper accounting of static variation through modeling.

This paper outlines the various technical challenges faced in the above regions and the solutions that were designed for them. While specific solutions are required in special circumstances, PETRONAS underlying objective is to acquire optimal data that will last the life cycle of a field where the surveys form the base cases for eventual reservoir monitoring through 4D seismics. Imaging through gas clouds, detection of fractures and improving resolution of thin pay sands and seals are some of our continuing challenges. With strong focus on proactive resolution of technical issues, the operational challenge of striking the right balance between quality, cost and efficiency is managed. Health and safety and preservation of the environment during seismic operations remain as an underlying principle of PETRONAS.
Well-Test Analysis in Gas-Condensate Reservoirs: Theory and Practice
Authors: Gringarten A.C. , Bozorgzadeh M. , Hashemi A. , Daungkaew S.
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Gas condensate reservoirs exhibit a complex behavior when wells are produced below the dew point, due to the existence of a two-fluid system, reservoir gas and liquid condensate. Different mobility zones develop around the wellbore corresponding respectively to the original gas in place (away from the well),the condensate dropout, and capillarity number effects (close to the well).Condensate drop-out causes a nonreversible reduction in well productivity, which is compensated in part by capillarity number effects.

All these effects can be identified and quantified from well test data. Tests in condensate reservoirs, however, tend to be difficult to interpret. Build-up and/or drawdown data are usually dominated by wellbore phase redistribution effects and the main analysis challenge is to distinguish between reservoir effects, boundary effects, fluid behavior and wellbore phase redistribution perturbations.

The paper compares theoretical well test behaviors in vertical and horizontal wells as obtained from compositional simulation with actual behaviors selected from more than twenty different gas condensate reservoirs. An interpretation methodology is described, which uses time-lapse analyses with different analytical and numerical tools to identify the probable causes of the pressure data behavior: two-region and three-region analytical composite models to represent the various mobility zones around the wellbore; a voronoi-grid numerical simulator to represent discontinuous boundaries; a multilayered analytical simulator to account for the geological description, and a compositional simulator to verify the fluid behavior. It is shown that, in addition to the usual well test analysis results, it is possible to obtain parameters required for reservoir simulation and well productivity forecasting, such as gas relative permeabilities at the end point, critical oil saturation, and the base capillary number.
Well-Test Analysis in Low-Permeability Multilateral Wells
Authors: Gringarten A.C. , Sharma R. , Rajvanshi A.K.
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Multilateral horizontal wells are used extensively in a number of reservoirs around the world, and particularly in the Middle- East. Development is often based on patterns of multilateral producers and multilateral injectors, and these, combined with complex reservoir geology, create well test pressure behaviors that are usually difficult to interpret. Ideally, well tests should be conducted one individual horizontal branch at a time and branch rates and producing lengths should be measured in order to decrease the non-uniqueness of the well test interpretations. In practice, this is not often possible and all branches are tested together. Low permeability reservoirs add to the difficulty, by reducing the information available within the normal duration of a build-up test. Although theoretical solutions for multilateral wells have been published in the oil literature, there are very few actual examples of well tests and even fewer detailed well test analyses.

This paper describes the analyses of well tests on several multilateral wells in a low permeability carbonate reservoir in the Middle-East. It is shown how a maximum of useful information can be extracted from the well test data, using a combination of techniques and tools, such as time-lapsed derivative analysis, analytical multiwell simulators, and deconvolution. Limitations and uncertainties in the analyses as a function of the data available are also discussed.
3D OBC Seismic Survey Design for Multiple Objectives
Authors: Painter D.J. , Al-Sharif S. , Qaradeh M. , Al-Kaabi M. , Furuya K. , Belaid K. , Al-Shateri A.
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

ADMA-OPCO and ZADCO are performing an intensive 3D OBC (Ocean Bottom Cable)seismic survey offshore Abu Dhabi with the twin primary objectives of defining the Thamama reservoir in an undeveloped structure and defining the overlapping Mishrif reservoir in a currently producing field. Survey value is increased by the reservoir characterization information that can be extracted from the seismic data. The structural Thamama target has different seismic acquisition geometry requirements to those of the stratigraphic Mishrif reservoir. OBC acquisition has a huge range of potential geometries and value and costs. This paper describes the processes that were used to reconcile the technical and economic conflicts.

Experience from a previous 3D OBC survey highlighted the generic problems in the area:Source-generated noiseStrong multiple interferenceAcquisition footprint

New survey design had to overcome these plus deliver high-resolution data(80 Hz at target level) to attain the stratigraphic and reservoir characterization objectives within a finite budget.

Team identification of key objectives was critical for the implementation of the successful survey design. Analysis and review of various modeling processes(acquisition geometry, seismic processing responses, acquisition economics)guided the team to an affordable solution that meets the geophysical objectives of a high-quality, high-resolution survey.

The process has provided a methodology that will be used as a basis for evaluating of cost versus quality in future surveys.
3D Geological Modeling-While-Drilling for Geosteering
Authors: Najjar N.F. , Jerome T. , Alshammery M.
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

The drilling of horizontal and multilateral wells has grown rapidly over the last decade. Successful geosteering of these wells in thin reservoir layers requires an accurate reservoir model that is updated in real-time with incoming logging-while-drilling (LWD) data. 3D geological modeling-while-drilling workflows, which utilize geostatistical techniques, were developed to facilitate model updating, while improving the accuracy and reducing the cycle-time of the geosteering process. A data link between LWD tools in the field and Saudi Aramco's offices in Dhahran provides real-time information to quickly update the 3D earth model, enabling multi-disciplinary geosteering teams to make fairly quick decisions regarding well bore trajectory changes.

In the initial step of the modeling-while-drilling workflow, a sector model which includes the planned horizontal well and neighboring wells is extracted from the existing full-field 3D geological model. Downscaling is applied to generate a fine resolution model along the planned well path. Using nearby welldata, the model is subsequently populated with reservoir properties such as porosity and gamma ray by means of variograms and geostatistical techniques, for instance Kriging or Sequential Gaussian Simulation (SGS). Pseudo well logs could be extracted along the planned well path for comparison with LWD measurements.

The 3D earth model is continuously updated during the drilling phase by automatically loading and integrating LWD data transmitted from the field. Quick model updating is done both for the structural and petrophysical components of the model. The new well data and revised earth model are analyzed in real-time, allowing the multi-disciplinary geosteering team to quickly make changes to the planned well path and convey those changes to the drilling engineer at the rig.

Field examples in various geological settings will be used to illustrate the modeling-while-drilling approach. It is an extremely useful technique that can be utilized to optimize well path, maximize well productivity, and reduce rigwait time. In addition, it allows professionals from different disciplines, whether in the field or geosciences centers, to work together in an integrated manner so as to reduce costs and improve well placement.
Coupling Complex Multiphase Pumps Surface Constraints to Reservoir Models for Optimising the Future Management Plan of a Mature North Sea Field
Authors: Foucault Hugues , Charles Thierry , Fulton Jonathan , Jaffrezik Vincent
Published: February 2016

Reservoir simulation is traditionally one of the main tools used for reservoir management plan definition. The situation gets more complex when the surface network plays an important role in the production profiles definition and behaviours, at least for part of the field life, as a bottleneck. New products have just been commercialised (PipeSim™, GAP™, Resolve™, R2SL™) but coupling complex surface network representation with reservoir simulators still remains at its beginnings. This paper describes a multi stage approach to model the impact of the multiphase pumps constraints of a Northern North Sea Field on the production profiles. From the simplest representation (GAP™ model plus look-up tables) to the most integrated, the implications of this model on the field development plan will be presented and the key issues of such a coupling discussed.

Introduction

Production management new era

Understanding behaviours of reservoirs, wells and surface networks, and forecasting the production profile over the entire field life have always been challenging tasks for the petroleum industry. They are usually addressed using separate simulators for every node of the production chain.

In this situation, interactions and influence of upstream or downstream events on the results of each model are only approximately accounted for. Reservoir simulators model the production from sandface to the wellhead only through the use of Vertical Lift Performance (VLP) tables and have a limited modelling of the surface piping. So production network effects on the behaviour of the overall system are not fully acknowledged. This may have a direct impact on the evaluation of the production targets that will actually be achieved. On the other hand, production network simulators typically use surface network model analysis that fully accounts for those effects but can only model the reservoir with a simple «inflow» model: material balance, decline curves or even fixed productivity index.

However, for the last few years, significant developments have been implemented to allow the construction of fully integrated models. Various types of controller for coupling reservoir simulation and surface facility network have been introduced in the literature. Since end 2004, the research tools have been finally proposed on the market, launching a new era for the simulation of the production chain from reservoir to surface.
Operating Experience with the SplitMR Machinery Configuration of the C3MR LNG Process
Authors: Brimm Allen E. , Ghosh Samiran , Hawrysz Daniel
Published: February 2016

Efficiency and economics have motivated RasGas Trains 3–5 to implement a novel compressor-driver arrangement comprising both propane and mixed refrigerant (MR) compressors on a single shaft. One Frame 7E gas turbine drives the LP and MP MR compressors while a second Frame 7E drives the propane and HP MR machines. With minor control system adjustments after startup, the refrigerant compressors in RasGas Train 3 are operating reliably.

Introduction

The propane precooled mixed refrigerant (C3MR) process developed by Air Products has been the dominant process technology employed in the LNG industry for over 30 years. This process uses a propane refrigerant system to chill the feed gas from ambient temperature to about -33oC and a mixed component refrigerant (MR) to chill the gas to LNG temperatures. Because pure propane is used in the precooling refrigeration cycle, the minimum temperature of this cycle is limited to the boiling temperature of propane near atmospheric pressure. The total duty that can be transferred to the propane refrigerant is thereby naturally limited to heat that can be transferred within this range.

Because of the propane's limited temperature range, one of the characteristics of the C3MR process arrangement is that the MR refrigeration system requires nearly double the compression power of the propane refrigeration system. The actual difference depends on the number of propane stages, the ambient conditions, the environmental cooling medium, and other process arrangements. To drive these refrigeration compressors, early LNG plants used steam turbines that could be sized to fit the required service (e.g. Marsa el Brega).Later projects determined that gas turbines drivers were a more efficient and less costly option for driving the compressors.

For procurement, maintainability and sparing purposes, an operating facility would prefer to have each of the compression services driven by the same type and model of gas turbine driver. For the C3MR process, such an arrangement is typically inconvenient due to the inherent power consumption mismatch between the propane and MR services.
Sour Gas Treating for LNG Production
Authors: Al-Mohannadi Ahmad , Fieler Eleanor R.
Published: February 2016

Produced natural gas must be treated to ensure high efficiency removal of sulfurous contaminants before it can be processed into liquefied natural gas (LNG).The selection of processes for removal of H2S may be a straightforward decision with extensive supporting data available. However, when the produced natural gas feedstock contains significant mercaptan, COS or other sour components, the process selection and design may become extremely complex. Several issues including process selectivity, energy requirements, total sulfur recovery, hydrocarbon coabsorption, and impact on downstream facilities will be weighed in this poster.

When technologies are being evaluated for use in pretreatment of gas for LNG production for the first time, the extremely high reliability and strict specifications of the LNG process must be taken into consideration. Often the processes under consideration are provided by licensors, and evaluation of data from historical applications should be undertaken cooperatively by the licensor and the operator to ensure that all facets of the operation are well understood. This is particularly challenging since it is rare to encounter exactly the same compositions and conditions more than once in the midstream.

LNG facilities operating in Qatar have installed multiple processes to maximize sulfur recovery at minimum cost. Based on the operating data from these units, ExxonMobil in cooperation with RasGas Company Limited (RasGas) has developed dynamic models and modified processes to optimize the operation of the existing facilities and the design of future ones. This work is aimed at high reliability, high efficiency, environmentally sound process units that support maximum LNG production at the lowest supply cost.

Background

RasGas has extensive experience in operating gas sweetening and sulfur recovery units. In addition to moderate concentrations of H2S and CO2 that must be removed from the produced gas, a variety of mercaptans and other sulfur containing species compose up to 400 ppm of the gas. In RasGas Trains 1 and 2, Sulfinol-D was chosen as the gas sweetening process, and the acid gas stream was directed to an Acid Gas Enrichment unit before entering the Sulfur Recovery Unit. This system has worked effectively to achieve the very low levels of total sulfur (< 14 ppm) required for the liquefied product.
Analyzing Microbial Improved Oil Recovery Processes From Core Floods
Authors: Kowalewski Espen , Rueslatten Ingun , Boassen Tony , Sunde Egil , Stensen Jan Age , Lillebo Bente-Lise Polden , Bodtker Gunhild , Torsvik Terje
Published: February 2016

Several mechanisms have been proposed to account for the increased oil recovery observed as a result of Microbial Improved Oil Recovery (MIOR) processes, both in laboratory experiments and field cases, but few of these mechanisms are verified. One of the reasons may be that these systems include living bacteria that ideally should be kept in a growing state during the investigations. This paper presents experimental results and a literature review where mechanisms are discussed, with main focus on changes in interfacial tension (IFT), wettability and permeability reduction during MIOR experiments. Special emphasis is put on wettability changes in a laboratory study of an MIOR core. The wetting conditions are studied by using an environmental scanning electron microscope (ESEM) that has been improved by modifying the cryogenic vacuum system for sample preparation. The ESEM equipment enables qualitative and semi-quantitative investigations of wettability changes after a core flood. The saturation profile in an MIOR core should show where the incremental oil is mobilized. An alternative technique for saturation determination is therefore presented, which is based on image analysis from electron images acquired in the same process as the wettability investigations. The number of cross sections with saturation estimations in this study is too few to make a reliable oil saturation profile (e.g., compared to a computer tomography scan). However, the average saturation from the images is close to the saturation calculated from the flooding process. The results of the study indicate that only small parts of the pore space have changed from their original strongly water-wet condition to a more oil-wet state.

Introduction

MIOR has shown significant potential for improving the recovery factor and should therefore be considered for implementation in producing oil fields and also in reservoir development plans. The technology is very cost efficient in a field case due to several reasons: When a water injection system is in use, the MIOR process can be initiated without major changes, thus the investment costs are low. Further, the use of biocides to limit the growth of bacteria producing H2S, and thereby causing reservoir souring, can be reduced since the MIOR process stimulates the growth of other bacteria which suppresses the growth of the H2S producing strains.
Hydrodynamic Conditions of Hydrocarbon Migration and Accumulation Exemplified by the Pomorsko, Czerwiensk, and Zarnowiec Oil Fields, Poland
Authors: Zawisza Ludwik Karol , Dylag-Wojna Elzbieta , Smulski Rafal Josef
Published: February 2016

The hydrodynamic conditions of migration and accumulation of hydrocarbons are exemplified by the Pomorsko, Czerwiensk and Zarnowiec oil fields in Poland.

According to Hubbert, under hydrodynamic conditions a buoyancy force and moving water exert major control over the distribution of water, oil and gas in a reservoir, causing the oil/water and gas/water contact to be tilted.

In this paper, a modified theory is advanced to define more precisely the position of potential oil and gas traps. The theory introduced here is more universal than Hubbert's theory because it accepts not only the groundwater motion (dynamic effect), but also the variability of the oil, gas and water density (static effect) and heterogeneity of reservoir rocks (capillary effect).

According to the presented method, to determine potential hydrodynamic entrapment of hydrocarbon, it is necessary to construct potentiometric maps for groundwater in terms of fresh water, maps of differential energy of oil or gas with respect to groundwater and maps of differential energy of oil or gas caused by capillary forces and then to add them up by superimposition.

Introduction

For determining hydrodynamic traps, Hubbert's potentiometric model of hydrocarbon accumulation is applied with its further modifications.

Potentiometric theory by M.K. Hubbert1 accounts for the influence of buoyancy force and hydrodynamic factor, related with the motion of groundwaters in a water-oil-gas bearing strata, on the locality of oil-water and gas-water contacts. M.K. Hubbert's theory disregards changes in the density of water, oil and gas, as well as the capillary pressure effect.

An original method of mapping hydrodynamic traps for oil is presented in the paper. It is a modification of the potentiometric theory by M.K. Hubbert.1 This novel approach accounts both for the influence of dynamics of groundwaters and also changes of reservoir fluids density values and the effect of capillary pressure values on the location of hydrodynamic traps. With this method it is possible to determine hydrodynamic traps location on a map, in 3D space, in the flowing water conditions.
Application of Real-time ESP Data Processing and Interpretation in Permian Basin "Brownfield" Operation
Authors: Oyewole Peter
Published: February 2016

Electrical submersible pump (ESP) operation, like many other segments of the oil industry, is recovering from having been drowned in large number of data, the aftermath of information technology revolution, and refocusing on effective utilization of reservoir and production data. This paper presents results of the application of real-time data processing and interpretation in a mature field (Permian basin) through operating and service company alliances. The process involves application of production system efficiency management coupled with newly developed advanced ESP technology and analysis tools-computer simulation software packages that could simulate actual ESP and downhole performance. Data are acquired from the wellsite using data acquisition panels and are sent over a secure network connection to a data hub. The data are also sent for intelligent real-time ESP data processing and interpretation. Well and reservoir monitoring, surveillance, analysis, and diagnosis are also performed. Active collaboration with producing companies at every stage of the process was encouraged through the formation of a new alliance. Finally, various recommendations and suggestions that could operate, optimize the ESP system, reduce well downtime, and prevent catastrophic and premature ESP failures were made.

This new approach to ESP operation reduces daily challenges in operating brownfields, such as keeping wells economically viable; solving production problems associated with operating mature assets in today's oil industry that is plagued with continuous declining of manpower resources. As might be expected, lease operating expense (LOE) and/or deferred oil production is reduced. Operational case studies and individual benefits are highlighted and included in this paper. This new approach is a significant departure from the conventional ways of operating ESP where service companies traditionally supply ESPs to producing companies to operate. This new alliance will have a decided influence on future ESP operation and the survival of many brownfields worldwide.

Introduction

ESP applications as a form of artificial lift method have continued to increase through the years, and significant growth is expected in the next decades as artificial lift requirements increase to a greater extent than current usage. ESP application covers all aspects of hydrocarbon exploitation. Its usage ranges from mature marginal onshore wells to high profile, deep-water subsea wells.
Reservoir Screening Methodology for Horizontal Underbalanced Drilling Candidacy
Authors: van der Werken Theo , Boutalbi Said Mohamed , Kimery David William
Published: February 2016

The general benefits of underbalanced drilling (UBD) can be explained in terms of:Drilling performanceReduced drilling problemsIncreased reservoir productivity and recovery by minimization of formation damage.

However, the absence of an easily applicable method to predict which reservoirs will benefit leads to an under-utilization of UBD by the industry. For that reason, the fuzzy logic expert system (ES) introduced in this paper was developed specifically to screen underbalanced candidates with respect to maximizing reservoir performance in terms of productivity.

The ES software considers basic reservoir properties and attributes such as fluid type, drive mechanism, lithology, porosity, water saturation, thickness, permeability, etc. Using algorithms and logic rules, various modules evaluate these input parameters to assess underbalanced candidacy based on the following criteria:The likelihood and severity of formation damageThe overall impact of the damage on productivity and recoveryThe ability to successfully treat this damage with conventional stimulation techniquesThe relative economics of UBD compared to conventional drilling, completion and stimulation techniques

In addition to a description of the ES, this paper discusses several case studies in which the output of the fuzzy logic ES is compared with published successful and unsuccessful UBD campaigns. The results demonstrate that the ES model can accurately predict the suitability of UBD for a given reservoir.

Introduction

UBD is not a new idea. For decades, operators have drilled various geological formations with different drilling fluids designed to exert a bottomhole pressure lower than the formation pressure, thereby allowing oil, gas and water from the formation to flow into the wellbore as drilling proceeds.

One may argue that the benefits of UBD are well documented, however, while few question its value, its perceived issues of safety and complexity - properly managing pressures and production during drilling and completion – are challenging the full acceptance of this drilling technique. In addition to these operational issues, it is more important to realize that UBD is not an economic solution for every formation. Anecdotal evidence suggests that applying UBD in unsuitable reservoirs can lead to more costly and unsuccessful wells. This paper introduces an ES that was developed to aid the successful selection of horizontal underbalanced candidate reservoirs. It is important to note that the proposed ES is specifically built to screen horizontal underbalanced candidates with respect to maximizing reservoir performance in terms of productivity and recovery.
Quantifying Uncertainty in Production Forecast for Fields With Significant History: A West African Case Study
Authors: Castellini Alexandre , Gullapalli Irene , Hoang Viet Thai , Condon Patrick John
Published: February 2016

Understanding the impact of subsurface uncertainties on production responses is an integral part of the decision making process. A more accurate quantification of the uncertainty band around production forecasts contributes to better business decisions. Traditional experimental design workflows, where a limited set of models represent the key uncertainties in subsurface parameters, might be well suited for new field developments. However, when a field has been produced for several years, all models have to be conditioned to available production data in order to obtain meaningful predictions. Data integration and uncertainty assessment of future performance of the reservoir are indivisible processes that cannot be generally addressed by simple techniques.

In this paper we present a method to tackle such complex inverse problems where highly non-linear responses are involved. The goal is to minimize an objective function that stands for the goodness-of-fit of the history-match. The key idea is to use high quality proxies of the objective function to accelerate the search for solutions. An efficient experimental design stage allow for the selection of key parameters while an optimization routine involving Genetic Algorithms (GA) is used to determine the best combinations of parameters. The models that reasonably honor the historical data are selected and provide an estimate of future production. The final distribution of the prediction variables defines the range of uncertainty conditioned to production history. The practicality of the methodology is demonstrated with a study of an off-shore field in West Africa that has several years of complex production history.

Introduction

Quantifying uncertainty in production forecast for a real field with complex history is a difficult task. Monte Carlo simulations coupled with probabilistic inverse theory is in general not practical due to the large number of simulations required. Efficient alternatives involving proxies and various optimization algorithms have been investigated. The fitness of the model to the observed data (history-match error function) is modeled using response surfaces of various nature, polynomial, kriging or spline for instance.
A Tracer Injection-Test Approach to Reservoir Characterization: Theory and Practice
Authors: Samaniego Fernando , Pulido Hector , Rivera Jesus , Camacho Velazquez Rodolfo , Perez Olave Victor Hugo , Martinez Bernardo
Published: February 2016

This paper presents new models and their solutions for the flow of tracers in reservoir, both radioactive and chemical, under constant mass flux conditions, which can be used for the design, evaluation and interpretation of injection test. The models developed consider homogeneous and naturally fractured reservoirs (NFR). For the case of NFR, a transient fracture-matrix tracer transfer is assumed. The models and the solutions acquired include the tracer lost to the matrix inaccessible (dead end) pore volume. The dimensionless groups used in this work resemble as much as possible those used in well test analysis.

Short and long time approximate analytical solutions for these tracer flow conditions are derived, which are useful to validate the general Laplace space solution, and for the interpretation of the tracer response in observation wells.

The solutions presented in this work were applied to real field interwell (observation) tracer responses, allowing the estimation of important fluid and reservoir parameters, such as the radial dispersion coefficient, Dr, and for NFR the average fracture aperture (width) and the block size.

The evaluation and interpretation of a pulse tracer test in a complex naturally fractured and stratified carbonate reservoir is evaluated and analyzed. In this test a chemical tracer Perfluoromethylcyclopentane (PMCP) was used.

Introduction

Tracers are substances that are added to the injected fluid with the purpose of studying the trajectory of the fluids inside a reservoir, as they advance toward the producing wells. A tracer should meet certain characteristics, among others: not interfere with the fluid flow, require a small concentrations and easy detection. Another purpose of introducing a tracer in the injected fluid is to detect the fractures preferential orientation or discontinuities in the reservoir. In any project of fluid injection, the channels of high permeability in the reservoir can quickly establish "short-circuits" for the injected fluid, reducing the efficiency of the process drastically, and in some cases can cause the failure of the project. The field tests with well to well tracer injection and the data analysis with the correct model, provide the possibility for the improvement of the reservoir characterization.
Mature Fields: The Keys to Winning the Marathon
Authors: Saleri N.G.
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

The term "Mature Fields" normally evokes connotations of rising costs and diminished expectations, yet the emerging sub-surface, with its utterly different sets of rules and attributes, is changing our paradigms and spurring distinctly higher expectations.

The increasing complexity of well architectures, higher levels of well intelligence and the real-time modality in well placement and field operations, are all products of recent technological advances and specifically the "computer chip". Advanced diagnostics is fast becoming the norm. Do they assure greening of mature fields? What should be our redefined Expected Ultimate Recoveries (EUR's)? Is 90% of Theoretical Maximum Recovery Factor a sufficiently bold target to shoot for? What are the major impediments to achieving higher EUR's for mature fields?

The answers invariably lie in modern reservoir management tenets, in-depth understanding of reservoir fundamentals, due diligence provisions and a wise selection of "smart-technologies" (the key operative word being "wise"). SaudiAramco's portfolio of hydro-carbon assets have, on average, a state of reserves depletion of less than 30%. On the mature end of the spectrum, Saudi Aramco'sAbqaiq Field has already crossed the 80% reserves depletion mark, yet is going strong on the strength of "smart technologies" and provides a real test as to what the smart technology dividend will be in terms of incremental recoveries and reduced costs.
The Darwin LNG Project
Authors: Yates D. , Schuppert C.
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

With the start of construction on the Darwin LNG Project in June 2003,ConocoPhillips will set a new benchmark for LNG projects by using aero-derivative gas turbines as drivers for the LNG refrigeration train.

Thirty-five years ago, in 1969, the Conoco Phillips-designed Kenai LNG Plant in Alaska delivered the first commercial LNG exported from the Western Hemisphere to Japan's Tokyo Electric Power Company, Inc. (Tokyo Electric) and Tokyo Gas Co., Ltd. (Tokyo Gas). This LNG operation pioneered the LNG trade to the Pacific Rim, which has grown from less than 1 MTPA in 1969 to more than 80MTPA today. The Darwin LNG Project continues this long-term relationship between ConocoPhillips, Tokyo Electric, and Tokyo Gas with the development of a single train grassroots LNG Plant in Darwin, Australia. This will also be the first LNG project where Tokyo Electric and Tokyo Gas are not just the buyers for the LNG, but also equity owners in the related upstream gas condensate and LPG reserves, pipeline, and associated LNG plant, an indication of the commitment toward a continued long-term relationship amongst the three companies.

The Darwin LNG Project will also introduce several new firsts in the evolution of LNG liquefaction technology. Again, thirty-five years ago, the Kenai LNG Project set the future trend for the LNG industry by becoming the first to use gas versus steam turbines for refrigerant compressor drivers. The Darwin LNG Project will continue to build on this history of innovation and evolution of the LNG industry by being the first LNG plant to use high efficiency, low emissions aeroderivative designed gas turbines for refrigerant drivers. The LNG Plant will also incorporate several other design features to reduce greenhouse gas emissions.

This paper will discuss the history of the commercial development of the Darwin LNG Project that resulted in the execution of a binding HOA and gasfield equity ownership with Tokyo Electric and Tokyo Gas. The various design innovations that will be incorporated into the LNG Plant to reduce greenhouse gas emissions will also be discussed. The paper will provide an overview of the project development activities, including initial contract development, current project schedule, workforce management issues, and the plant handover process.