bluuebunny/crossref_metadata_2025 huggingface dataset:
Multi-Layer Steady-State Injection Test With Higher Bottomhole Pressure Than the Formation Fracturing Pressure
Authors: Davletbaev Alfred , Baikov Vitaly , Ozkan Erdal , Garipov Timur , Usmanov Timur , Asmandiyarov Ruslan , Slabetskiy Andrey , Nazargalin Eduard
Published: February 2011

Field A considered in this paper is an oil field characterized by low permeability and large vertical variability of formation properties. Injection and production take place in commingled multi-layer zones of Field A. Wells are hydraulically fractured across the entire stack of the producing layers. In the injection wells, the bottomhole pressure is higher than the formation fracturing pressures causing continuing growth of fracture length.

This paper discusses 60 multi-rate injection tests to determine the injection profiles in Field A. The tests consisted of continuous measurements of the bottomhole pressures for several constant injection rates. Measurements were made for three different injection periods with pressures below and above the formation fracturing pressure. Each injection period lasted until steady-state conditions were established. Layer injection rates were determined from stabilized injection profiles obtained by spinner surveys before the tests. Layer properties were determined by matching the constant injecting rates and layer pressures for multiple injection periods.

Test results demonstrated that well performances in Field A could not be described by known solutions for a constant fracture length. The non-linear relationship between the steady-state pressure and injection rate indicated that continuous change in fracture geometry had to be taken into account. These tests were useful to determine individual layer injectivities, current formation pressures and fracture opening pressures of each layer.

Based on the results, it is concluded that multi-layer, multi-rate injection tests are useful to monitor layer pressure distributions and effectively produce multi-layer fields. The Simultaneous Separate Injection (SSI) technology used in these tests provides the ability to control layer injection rates and maintain uniform production from multiple layers. The SSI technology also allows injecting controlled volumes simultaneously into several layers through one injection well. Comparison of the tests using the SSI technology and adjusted valves demonstrates redistribution of injection rates from a higher- permeability layer to a lower-permeability layer.
Effect of Acid Spending on Etching and Acid Fracture Conductivity
Authors: Pournik M. , Li L. , Smith B. , Nasr-El-Din H. A.
Published: February 2011

In acid fracturing, while the near wellbore area of the fracture receives fresh, unspent acid, sections of the fracture further down the length receive partially spent acid due to reaction of acid. As a result, there is a distribution of acid concentration along the fracture length. However, almost all experimental studies on acid fracture conductivity have been conducted with fresh acid, which is representative of what occurs near the wellbore.

An experimental study was conducted to investigate the effect of spent acid on the resulting fracture conductivity in a laboratory facility designed to perform acid fracture conductivity characterization. Gelled HCl acid systems with different degrees of acid spending were used to etch fractured cores under identical treatment conditions, which were set to mimic field conditions. Detailed etched surface characterization, fluid analysis, and conductivity measurements were performed on acid etched fracture faces.

Experimental results clearly show that the amount of rock dissolved and actual etching pattern depend highly on acid concentration. While there was less fracture face etching with more spent acid system, etching pattern also changed with acid spending, which sometimes offset the additional etched volume of unspent acid. As a result, the retained conductivity was generally higher for the more spent acid and the decline in conductivity with closure stress was more subtle with the spent acid due to probably less weakening of the fracture face.

While there have been many developments in enhancing the etched length of acid fractured wells, a major reason for the lack of long etched fractures is acid spending along the fracture. In order to understand the etched fracture profile, there is a need to realize how the degree of acid spending limits etching and affects the resulting fracture conductivity. Based on the newly discovered effect of acid spending on conductivity, acid etched length and conductivity can be predicted more accurately and acid fracture treatments better designed.
Engineering Approaches' Progress in Calculation of Inhomogeneous Turbulence in Pipelines
Authors: Kharlamov S.N. , Alginov R.A.
Published: February 2011

Results of calculation of unsteady direct and degenerating swirl turbulent flows of liquids and gases in pipes and channels with short and extensive flow regions are presented. Swirled flow hydrodynamics is investigated in details in the area of inlet into the pilot section. In modeling of turbulent heat-and-mass transfer there used 2nd order closure schemes with differential equations for Reynolds stress tensor with original low-reynolds restricting base of k-L equations. Mechanisms of generation and development of reverse flows, degeneration and rearrangement of swirl flow into direct one are analyzed in broad range of governing parameters. Developed algorithm accuracy in prediction of local and integral parameter distribution of complicated swirl flows are illustrated by means of comparison with experimental data.
Estimation of "Very-Difficult-to-Identify" Data for Hole Cleaning, Cuttings Transport and Pressure Drop Estimation in Directional and Horizontal Drilling
Authors: Ozbayoglu M. Evren , Ettehadi Reza O. , Murat Ozbayoglu A. , Ertan Yuksel
Published: February 2011

As the inclination of a wellbore increases, cuttings start having a tendency to accumulate in the lower section of the wellbore, and develop a cuttings bed. This developed bed causes a reduction in the flow area, an increase in the friction between the drillstring and the wellbore, leading to an increase in torque, decrease in force transfer to the bit, and lose control on the bottomhole pressure. Finally, drilling rate decreases. Estimation of total concentration inside the wellbore is not an easy task. Moreover, moving cuttings and fluid dragging them to move have different relative velocities inside the wellbore, causing variations in pressure drop. Although there are many attempts to estimate the cuttings concentration and slip between the cuttings and the fluid using mechanistic models and empirical correlations, the performances are limited either with the strong assumptions made, or the experimental facility capabilities. This study aims to determine some of the very-difficult-to- identify data for estimating total pressure drop and total cuttings concentration inside the wellbore. Extensive experimental work has been conducted using a cuttings flow loop at horizontal and inclined wellbores. Tests have been conducted using water to simulate low viscosity fluids. Data has been collected for a wide range of flow rates, cuttings injection rates and pipe rotation speeds. All experiments have been recorded using a high-speed digital camera. Images have been processed using special algorithms, and volumetric distributions of cuttings and fluid can be identified very accurately. By comparing consecutive images, very valuable information has been collected about the accumulated cuttings amount, concentration of moving particles, their relative transport velocities, slip velocity between the phases, the friction factor on the stationary bed, etc. Since the images are digital, information collected is converted into numerical values, and semi-empirical equations are developed as a function of known drilling parameters. The obtained information is tested in simple mechanistic models for estimating pressure drop inside a wellbore with the presence of cuttings, and the performance of the model is tested by comparing the results with the measured ones. It is observed that, after supplying the very-difficult-to-identify information to the mechanistic model, the performance of the mechanistic model improved very significantly. The information provided will improve the design of long extended reach wells while estimating hydraulic requirements, and make it possible to have a better understanding of what is really happening inside the wellbore.
FIB/SEM and Automated Mineralogy for Core and Cuttings Analysis
Authors: Lemmens H.J. , Butcher A.R. , Botha P.W.S.K.
Published: February 2011

New high resolution microscopy solutions are being used for conventional and unconventional reservoir characterization at both micron and nanometer scales. Focused Ion Beam and Scanning Electron Microscope (FIB/SEM) technology combines the high resolution of a SEM with the precise milling capability of a FIB. 3D reconstructions with resolution of a few nanometers are made possible, leading to new insights into rock fabrics, porosity and permeability. Illustrative FIB/SEM data of shale and carbonate reservoirs are presented. High resolution imaging resolves the complex micro-structure and microporosity present in the shale and carbonate.

Automated Mineralogy, another emerging solution for petrological analysis, involves the ultrafast mineral and textural mapping of cuttings and cores, achieved through a fully integrated system comprising automated SEM imaging and energy dispersive X-ray spectroscopy (EDS). Through customized analysis software, the resulting false-colored images can be used to quantify the mineralogy, grain size, grain density, porosity, and lithotypes, on a cutting-by-cutting or core-by-core sample basis. These data in turn can be used to provide objective inputs into geological, geophysical, and engineering interpretations of reservoir properties.
Characterizing the Precambrian Petroleum Systems of Eastern Siberia: Evidence from Oil Geochemistry and Basin Modeling
Authors: Everett Melanie A.
Published: February 2011

Uncertainties regarding the number, location, and areal extent of Precambrian petroleum systems in Eastern Siberia are primarily attributed to a lack of direct source rock data. This study provides an indirect characterization of source rocks contributing to petroliferous areas (PAs) in the southern Lena-Tunguska region through an assessment of available geochemical data from oils and gases contained in reservoirs from the Vendian through lower Cambrian. Geochemical data and basin modeling were used to: (1) establish the number of source rocks contributing to hydrocarbon accumulations; (2) define source rock depositional systems and lithology; (3) estimate source rock thermal maturity; and (4) predict source location and migration patterns.

In this study, geochemical interpretations are made on oil and gas data available from the published literature and GeoMark Reservoir Fluid Database and include comparisons of samples from the Nepa-Botuoba, Angara-Yenisey, Katanga Saddle, and Baykit PAs. One-dimensional maturity models of pseudo-wells in the Nepa-Botuoba and Angara-Yenisey PAs are constructed incorporating inferred source rock characteristics to constrain the timing and thermal histories of the petroleum system components. Results from this study confirm that the Eastern Siberian oils are non-biodegraded and were generated within the main oil window from Precambrian sources. Significant geochemical differences among oils from the Nepa-Botuoba, Angara- Yenisey, and Baykit PAs strongly support hydrocarbon generation from three distinct source rocks. Furthermore, biomarker and bulk oil parameters indicate lateral hydrocarbon migration across the Nepa-Botuoba anteclise that originated from a single source. These findings both advance the current understanding of the East Siberian petroleum systems and have direct consequences for prediction of fluid characteristics at the field and reservoir scales.
Fully Stochastic Screening and Ranking on Entire Reservoir Portfolios - A Case Study for Candidate Recognition for Waterflood Implementation
Authors: Graf T. , Zangl G. , May R. , Hartlieb M. , Randle J. , Al-Kinani A.
Published: February 2011

Waterflooding is among the oldest and perhaps most economical of Enhanced Oil Recovery (EOR) processes to extend field life and increase ultimate oil recovery from naturally depleting reservoirs. High oil prices provide incentive for companies to look deeper into their reservoir portfolios for additional waterflooding opportunities. Time and information constraints can limit the depth and rigor of such a screening evaluation. Time is reflected by the effort of screening a vast number of reservoirs for the applicability of implementing a waterflood, whereas information is reflected by the availability of data (consistency of measured and modeled data) with which to extract significant knowledge necessary to make good development decisions.

A new approach to screening a large number of reservoirs uses a wide variety of input information and satisfies a number of constraints such as physical, financial, geopolitical, and human constraints. In a fully stochastic workflow that includes stochastic back-population of incomplete datasets, stochastic proxy models over time series, and stochastic ranking methods such as Bayesian belief networks, more than 1,500 reservoirs were screened to reduce their number by one order of magnitude to about 100 potential candidates that are suitable for a more detailed phase of evaluation. Numerical models were used to create response surfaces that capture the sensitivity and uncertainty of the influencing input parameters on the output. Reservoir uncertainties were combined with expert knowledge and environmental variables and were used as proxy model states in the formulation of objective functions. The input parameters were assigned in a stochastic manner. The output is represented by a ranking of potential waterflood candidates.

The benefit of this approach is in the inclusion of a wide range of influencing parameters while at the same time speeding up the screening process without jeopardizing the quality of the results.
Implementation of Real Time Monitoring System for Priobskoye Field
Authors: Baryshnikov A. , Sidorenko V. , Tychinski A. , Timokhovich Y. , Safronov D. , Gladkov A. , Kondakov D.
Published: February 2011

The concept of “Intelligent Field” is becoming a promising strategy in the oil and gas industry. This approach includes several levels (components) of information management: Data gathering system (data channels, data transmitters);Data processing and analysis (simulation and monitoring tools);Data integration solutions;Feedback (well response, ESP frequency response).

This paper describes the application of the data gathering and integration process supported by the data processing and simulation tools in the Southern License Territory (SLT) of Priobskoye Field (West Siberia). The proposed solutions provide a suitable base for daily monitoring of problematic elements with the appropriate feedback to the related services if a problem occurs.

These solutions were implemented to monitor the production process in the SLT of Priobskoye field, they were successfully used to reach the main goals: Gathering of the field information in real time;Introduction of the tool to control artificial lift production for our technologists;Access to the information about problematic wells at least once per day;Visual and analytical reports related to problematic wells;Field development planning and monitoring tools for specialists involved in waterflood simulation and management.

The results of this work can be used to analyze the learning process, to evaluate the prospects of “return on investments” put into the simulation models, which in our case are constantly upgraded and used in work. The important result of this project is a transparent and fast decision-making process supporting oil production activities.
Remote Monitoring and Production Optimisation in Shell
Authors: van den Berg Frans , Goh Keat-Choon , van Donkelaar Edwin , Parchewsky Robert
Published: February 2011

With the advancement of technology, fields are increasingly monitored in real time, remotely from the office. This applies to wells and facilities alike. Shell has applied a range of capabilities across the assets worldwide. The capabilities include: –Real time monitoring and optimisation of wells–Virtual metering–ESP surveillance - real time monitoring and remote control–Advanced Rotating Equipment monitoring–Integrated Production System Modelling–Collaborative Work Environments for integrated decision making

The paper describes how these techniques are used in Shell's operations. They enable asset staff to deal with a wider range of issues faster and more efficiently while bringing global expertise as required in near real time. This involves integration across a range of disciplines, for fast and effective decision making.
Striving for Zero Serious Injuries: Experience of the Oil Operator in Western Siberia
Authors: Samoylova O.
Published: February 2011

Safety has been one of the most critical areas calling for rapid and fundamental improvement in the global Exploration and Production sector over the recent decades. This has resulted in recognized industry examples of outstanding safety excellence that enabled some companies to go up to five consecutive years or more without a lost time injury because they have done an excellent job of engineering and guarding their plants and equipment, providing personal protective equipment and training employees in safer systems and procedures.

Although there are unquestionable reasons behind a safety focused oil and gas production including tragic events of lost lives and ruined businesses that were caused by poor safety management and lack of safety leadership in the past, not too many companies have managed to embrace and exercise safety through every day practical commitment and action. This might seem and really does become even more difficult in the harsh environment of the Western Siberia oilfield with its inherited safety standards and widely spread risk taking practices. And that is exactly the challenge being faced by the company.

Our experience suggests that there are key success factors but also some misconceptions and undervalued opportunities for making a difference in safety as proven by our own operations.

The main purpose of the paper is to share company's learnings from implemented Goal Zero Must Win framework. The currently taken approach can be divided in three mainstreams aimed at: 1) behavior change -inspired by the company leadership who enable and encourage “compliance and intervention” culture whereby safety becomes positive, proactive and natural; 2) delivery against focused action plans - associated with high risk areas with biggest exposure, project oriented and led by the company management team members; 3) life saving rules - communicated, embedded and enforced.

We hope that experience shared will serve as a practical guide and best practice source for those companies working in the Russian Federation that put the goal of “No harm to People” as their number one priority.
Foaming Mitigation and Process Upset Management: Operation Case Study
Authors: Nengkoda Ardian , Hajri Mohd , Naabi Saud , Kindy Azzan , Reerink Hendrikus
Published: February 2011

Since commissioning of the new main bulk separator in X, Field Petroleum Development Oman station in 2008; the separator had gone through serious of problems of fluid foaming. Throughout 2009 and until early 2010, X station gone through big instability of production issue mainly due to the main bulk separator upset which resulted in measurable production impact. Some amount of water is exported to main station via the GRE line that causes increase in the GRE line pressure and therefore forced to shut-down of X oil producers. This disturbance in the system as flow assurance issues, observed at least every 2 months with a minimum of 2 weeks per each disturbance. The average water cut in the export of X Field in 2009 was around 7% although during the upsets it reached sometime up to 85%. In November 2009 an integrated multi disciplinary team was formed to look at this issue and action plan has been set after identifying the route causes of the instability and foaming problems. The latest production and process upset in the system during the past 2 months is even worse than the 2009 upsets (with bigger lost production impact), and took longer than usual with all the actions and measures that has been taken earlier. Based on the fluid characterization study, emulsion and foaming testing, the root caused of foaming is due to excessive CO2 content from reservoir, sodium meta silicate, carboxylic acid and shearing by artificial lifting ESP downhole and the proactive surveillance and injection of novel anti foaming polymer type combined with emulsion breaker chemicals as mitigation is success to inhibit foaming.
Integration of 4D Seismic to Add Value: The Enfield ENC01 Sidetrack Story
Authors: Medd Daniel , Thomas Peter , Sibbons Craig , Smith Megan , Ali Amna
Published: February 2011

The Enfield oil field, on Australia's Greater North-West Shelf, has now produced over 50 million barrels of oil. The field is a water flood development with both downdip and updip water injection wells. Faults and baffles within the reservoir create a complex dynamic system that can only be understood with the integration of 4D seismic data. Monitor surveys in 2007 and 2008 have made major contributions to reservoir management and identification of infill drilling opportunities.

This paper highlights the value of fully integrating 4D seismic into reservoir management, and the rationale for sidetracking a water injector well at short notice to provide pressure support to the field's largest producing oil well. Oil production from this well was dropping rapidly and the need to improve pressure support was clearly evident. It only became clear how best to achieve this upon delivery of new 4D results.

The reservoir model directed attention towards insufficient water injection downdip and the opportunity to sidetrack these injection wells closer to the production wells was under consideration. However, results of the December 2008 4D monitor survey became available at this time, and indicated a reservoir baffle between the oil producer and the downdip injectors, which diverts water away from the producer. Thus improving injectivity at these downdip water injector wells would have had little impact on the failing producer.

The 4D seismic data also indicated that water from a key updip injector was being deflected away from the producer. The difference here was that the baffle was close to the water injector and not the oil producer. The opportunity to sidetrack this water injector across the baffle was rapidly progressed, with the injector sidetrack drilled and completed in mid 2009.

Pressure support at the oil producer was seen within days of commencing injection in the sidetracked well. Revenue from increased oil production paid back the cost of the injector sidetrack and the 4D monitor survey within two months of startup. The involvement of all subsurface disciplines was a key success factor in the outcome.
Mechanical and Geochemical Assessment of Hydraulic Fracturing Proppants Exposed to Carbon Dioxide and Hydrogen Sulfide
Authors: Bremer J. M. , Mibeck B. A. , Huffman B. W. , Gorecki C. D. , Sorensen J. A. , Schmidt D. D. , Harju J. A.
Published: February 2011

The Energy & Environmental Research Center (EERC) has conducted a study to determine the mechanical and geochemical changes experienced by proppants as a result of exposure to CO2 and H2S in simulated reservoir conditions. This study was conducted under a cooperative agreement with the U.S. Department of Energy's National Energy Technology Laboratory with the goal of investigating factors affecting production in the Bakken Formation of North Dakota.

As hydraulic fracturing is critical to successfully producing tight oil, proppant longevity is also critical to maintain fracture conductivity to the wellbore. Long-term conditions such as reservoir souring and the potential for CO2 enhanced oil recovery (EOR) within the Bakken were considered in the study to examine the effects on proppant strength. The possibility exists for proppant degradation due to the large amount of fluids that travel through fractures, the high surface area of the proppant within the fractures, and the already taxing subsurface conditions.

In order to understand the potential degradation of proppant compressive strength, samples were acquired that represent common proppants, including both natural and synthetic materials. Samples were subjected to simulated downhole conditions and exposure to supercritical CO2 and acid gas containing 85% CO2 and 15% H2S. Effects of the presence or absence of brine was also examined. Samples removed from the reactor were subjected to one-dimensional confined compressive strength testing and sieve analysis to examine the amount and size of damaged material compared to baseline, as-received material.

Preliminary results indicate that all proppants show varying degrees of strength loss postreaction, and work is being performed to determine whether the causation is a product of brine interaction, reactor pressurization, or reactor depressurization, or is indeed due to mineralogical gas/proppant interactions. The results of this study will aid in the selection of optimal proppant materials for long-term or multiple-use performance in unconventional oil shale and gas shale production wells, as well as potential for retrofitting a well for injection purposes. The work has further applications with the potential use of hydraulic fracturing for increasing the injectivity of CO2 relative to carbon storage.
Waterflood Induced Fracture Modeling in West Salym Field
Authors: Aniskin Alexander , Chmuzh Irina , Sakhibgareev Rushan
Published: February 2011

Waterflooding is a common practice recovery method in West Siberia oil fields. SPD started water injection in Dec 2005 and, since then, there are more than 100 injectors operating in the field. It is well established already that a successful waterflooding can only be achieved with a proper well and reservoir surveillance and management. Field observations indicate that injection is taking place under fracturing conditions. In order to manage and control this process SPD has put a surveillance plan in place which include performing regularly (modified) Hall-plot analysis, temperature and production logging (TLP/PLT), pressure fall-off (PFO) tests, and step-rate tests.

The case study, presented in this paper, describes the approach of induced fracture modeling of one of injectors in the field. An in-house coupled fracture/flow simulator (FRAC-IT) is used for this purpose. First, data assimilation/history match is performed by calibrating FRAC-IT simulation model with the fracture size and BHP data based on PLT/PFO analysis. This covers the historical period of injection. Subsequently, forward simulations are run to predict fracture sizes for a number of future infill and waterflood pattern conversion scenarios. Finally, since water quality influnces on fracture dimensions and containment, recommendations related to injection water quality specifications are made.

An important outcome of the study is establishing an approach and the workflow required for modeling induced fracture for complex field operations.
Viscoelastic Surfactant Diversion: An Effective Way to Acidize Low-Temperature Wells
Authors: Toseef A. , Beaman D. J. , Birou P.
Published: February 2011

A gel-based, crosslink-diverter system has been the fluid of choice for a wide range of temperature applications for carbonate acidizing treatments in Qatar. Recent field experiences with acidizing low-temperature wells (100 to 140 °F) indicated the need for a chemical diverter system that develops viscosity rapidly enough to divert acid in a continuous pumping stream.

A viscoelastic surfactant- (VES) based acid-diverter system was selected for a trial treatment because of its attributed phenomena of viscosity generation. Viscosity development for this system is a function of divalent cations generated as a result of HCl acid reaction with carbonates. Laboratory tests were performed to evaluate a viscosity profile for viscosity development versus acid spending. It was established that using 15% HCl mixed with the VES system would provide sufficient reaction rates at these low temperatures to generate an adequate amount of the divalent cations for rapid viscosity development. Formation fluids act as breakers for the VES gel. Treatment guidelines were developed based on the sensitivity of VES systems to iron content, corrosion-inhibitor concentration, and incompatibility with emulsified acids.

Field application of the system showed promising results by providing better acid diversion for these low-temperature wells compared to the gel-based crosslink diverter. Downhole-pressure plots confirmed the rapid viscosity development as predicted from the lab tests. Field mixing and pumping guidelines were developed for further application of the system based on the learning from these field applications.

This paper presents various guidelines for successfully using the VES-based diverter system in low-temperature wells for effective acid diversion. Lab-test procedures and results to serve as a guideline for such applications are discussed. Case studies are shown to demonstrate the effectiveness and success of carbonate acidizing treatments using VES systems for diversion in low-temperature wells.
Technology Implementation in ADCO
Authors: Laws M. S. , Attardo A. J.
Published: February 2011

Technology implementation is becoming increasingly important in ADCO as fields mature, higher reserves recovery is expected and improved performance is needed. ADCO has recently implemented a new process to more efficiently and effectively implement those subsurface and drilling technologies that could add the most value to ADCO. Following engagement sessions with all of the Subsurface and Drilling Teams, fifteen strategic technologies were identified that have pan ADCO benefits.

Implementation of these technologies was then energised by setting up organizational units or with the creation of dedicated Technology Focus Groups (TFGs) with clearly defined Terms of Reference. As most of the technologies are being facilitated through TFGs, which are new organizational concepts for ADCO, this will be the focus of this paper. The TFGs are made up of a cross section of staff from ADCO, as well as Service Companies, charged with ensuring that the best interests of ADCO are considered during implementation planning and field trialling of technologies.

Initial results are encouraging. The TFGs are already establishing themselves and gaining acceptance as a means of sharing knowledge across ADCO as well as facilitating technology implementation. Indeed, a number of key technologies have already been progressed to the pilot stage, which is much faster than our previous experience.

Each selected technology is being sponsored by a Senior Manager and a Corporate Executive oversees Technology Implementation across ADCO.

The purpose of this paper is to describe the process and strategy that has been set up in ADCO to mature and deploy subsurface and drilling technologies. It also provides an overview of progress made to date with implementing this strategy.
Case Studies of Successfully History Matched Reservoir Simulation Models using a Powerful Optimiser being of Limited Predictive Value
Authors: Kathrada Muhammad , Carter Jonathan N.
Published: February 2011

History matching production data using finite difference reservoir simulation models has been and will always be a challenge for the industry. The principal hurdles that need to be overcome are finding a match in the first place and more importantly a set of matches that can capture the uncertainty range of the simulation model and to do this in as short a time as possible as the bottleneck in this process is the length of time taken to run the model. Particle Swarm Optimisation (PSO) is a class of evolutionary algorithms that have shown much promise over the last decade. Essentially a swarm of agents are allowed to search the solution hyperspace keeping in memory each individual’s historical best position and iteratively improving the optimisation by the emergent interaction of the swarm. This method draws parallels from the social interaction of swarms of bees, flocks of birds and fish shoals. An intrinsic feature of PSOs is their local search capability. A sequential niching variation of the PSO has been developed, viz. Flexi-PSO, which enhances the exploration and exploitation of the hyperspace and is capable of finding multiple minima.

This study looks at the implementation of Particle Swarm Optimisation in history matching finite difference simulation models. The method is applied to two synthetic case studies (one based on a real field model) to find multiple distinct history matches. The resulting matches are then forward predicted to gauge their effectiveness in matching the truth case prediction.
Production Behaviour of Gas Hydrate Under Hot Sea Water Injection: Laboratory Case Study
Authors: Nengkoda A. , Budhijanto B. , Supranto S. , Prasetyo I. , Purwono S. , Sutijan S.
Published: February 2011

In 2004, Indonesia has discovered 850 trillion cubic feet (tcf) of potential gas hydrate deposits as alternative energy to fuel oil at least in two locations, in South Sumatra's southern waters extending to West Java (625 tcf) and in the Sulawesi sea (233.2 tcf). The laboratory and simulation production behaviour of gas hydrate under hot sea water injection as alternative of Indonesia hydrate production, have been done under laboratory condition with combination of synthetic hydrate and porous sediment. Some flow assurance challange issued also have been investigated. These preliminary study are to investigate the temperature profile distribution, operational parameters and flowing characteristics of the dissociated gas and water from hydrate in porous sediment systems under synthetic hydrate and experimental setup. The experiments have been conducted by injecting hot sea water where composition is near to Indonesian sea water characteristics with different temperatures and rates. The result find that the gas production rate increases with time until reach maximum, and then it begins to decrease. The injection water temperature and rate, as well as the hydrate content in the synthetic sediment, all influence the energy ratio of thermal stimulation production. The high temperature sea water injection found potentially creating scale problems.
Sub-surface and Surface Integration to Sustain Gas Production in a Field, Peninsular Malaysia Operations, PETRONAS
Authors: Hadi Sriyanta , Osman Azmee B , Hasnan Zairinda Bt
Published: February 2011

A Field is an offshore field located at offshore of Peninsular Malaysia, facilitated with an integrated oil and gas processing plant, water injection facilities and gas lift infrastructure. The field was brought to oil production in end of 2001 and achieved the peak production of about 120 Mbopd in 2005. In early of 2002, it started gas production at an initial rate of about 300 MMscf/d which is currently maintained at about 300–350 MMscf/d. The crude oil production peak was followed by a moderate decline over the next three years. Besides crude oil and gas production, the field also produces condensate as by product while producing gas. It was recognized that a proactive field management strategy was required in order to minimize any further production decline as the field production forecast showed a declining trend. Since A Field is one of major gas contributors, its gas production sustainability is very important to fulfill the gas demand in the region. The current gas sources in A Field are natural gas reservoir as the main source and the associated gas from oil production. It was recognized that subsurface and surface integrity is the key success for sustaining A Field gas production. The integration is important to ensure proper planning and execution for gas development within the A Field area as well as sustaining the crude oil production. There are several alternatives to maintain gas production. The analysis presented here describes the use of an integrated approach involving multi-disciplines to achieve the most suitable decision and maximize value creation focusing on A gas sustainability.
A Proven Approach Towards Plant Piping Integrity Management
Authors: Aljaberi Manea , Kamel Hasan
Published: February 2011

Plant piping integrity management is considered as a big challenge for upstream/downstream operators worldwide because of the complexity of plant piping loops and the resources required to build and maintain solid inspection database. Statistics from two upstream operators indicates that majority of leaks within operating plants occurred at plant piping loops rather than main static equipments and with majority of operating facilities exceeding its intended design life (40 years), the Middle East upstream/downstream industry is expected to see a higher rate of failures in the coming years unless a paradigm shift is made in plant piping integrity management. Hence it is essential to focus integrity initiatives on plant piping in order to achieve higher overall plant integrity status, without ruling the need for integrity management for other plant equipments. This paper is presenting a unique structured approach towards plant piping integrity management which was deployed by two upstream Operators in the period from year 2004-2008 and from year 2007-2010 respectively. The piping integrity management approach presented in this paper is based on multidisciplinary engineering team consisting of process, CAD-draughting, Corrosion, Inspection, NDT, Piping, Mechanical, Maintenance data management disciplines. The approach was proven to enhance plant integrity status by evidence from failure statistics trends which are presented in this paper. Several challenges were faced during the implementation; the case studies discuss how the two Operators overcame these challenges and developed a systematic integrity review using existing Computerized Maintenance Management System ERP package. Nevertheless, the implementation of this approach enabled the two Operators to identify weak design specifications (e.g. piping support design) and supported the upgrade of the piping specification to avoid reoccurrence of the frequent failures. In the two case studies, the Operators were leading a rehabilitation program addressing non-integral piping systems over the entire facilities. The piping integrity management approach discussed in this paper is generic in nature and can be applied by any upstream/downstream operators in the world with high rate of success. It is expected that this topic will be of a big interest to all upstream/downstream operators in the region and possibly worldwide. The results of the implementation of the subject approach confirmed suitability of this approach in enhancing plant piping integrity, and therefore overall plant integrity status.
The Application of ESPCP in China Offshore Oilfield
Authors: Feng Bao , Meng Weibin , Li Anxia , Zhang Xiaocheng , Li Liangchuan , Wu Bingchang , Li Xin
Published: February 2011

ESPCP is a combination of Progressive Cavity Pump (PCP) and Electric Submersible Pump (ESP) motor as an artificial lifting system in oil & gas industry. So ESPCP has also integrated the advantages of both PCP and ESP. It is considered as the most suitable artificial lift system for some special oil quality or well conditions, such as high viscosity oil, sandy oil, deviated or horizontal well and offshore platform. Besides, the PCP’s energy saving has also well reserved in ESPCP.

Sanyang Co. Ltd. began its researches and developments on ESPCP since 1996, and now it succeeds to supply 2 series of ESPCP for 7" casing (150 serial) and 9 5/8" (200 serial) casing. And over 150 sets of ESPCP units have been tried and applied in different well conditions in CNOOC (China National Offshore Oil Company), SINOPEC (China Petroleum & Chemical Corporation) and CNPC (China National Petroleum Company) offshore oil fields. These successful cases have covered the viscosity 100~8000 mpa.s, inclination angle at pump depth 20~86°, pump depth 900~1800m, flowrate 20~240 m3/d, and the average life span is over 400 days.

The key point of ESPCP system is the reliable downhole mechanical transfer system (including the motor reducer) and the PCP elastomer suitable for high speed running. Sanyang Co. Ltd. Cooperated with PCM had successfully solved these technical bottlenecks of ESPCP syste,. This paper will discuss the advantage, technical highlights, the technical specifications and case stories of Sanyang-PCM ESPCP.
When Unconventional Becomes Conventional
Authors: Stefik R. , Paulson K.
Published: February 2011

British Columbia has seen near exponential growth in the areas of the Horn River and Montney unconventional shale gas plays situated in North Eastern B.C. (figure 1). The original gas in place volume for the Montney and the Horn River basins have not been formally calculated but have been estimated at more than 500 Tcf and continues to be revised upwards as new and more refined information is obtained as development takes place. The Cordova Embayment and Liard Basin, east and west respectively of the Horn River Basin, are at early stages of assessment but promise additional massive gas-in-place values.

Approximately 5 years ago, industry experts were predicting a drastic reduction in viable gas production from the Western Canada Sedimentary Basin, and North America in general. Market predictions were favouring investment in import terminals for liquefied natural gas (LNG) where gas from offshore suppliers could be imported and moved through the North American transportation grid to market. Regulators were anticipating an influx of LNG facility applications as well as a myriad of infrastructure modifications to handle the resulting new flow regime.

In five short years, this dire future has been completely reversed due to the advent of economically viable methods to access gas trapped in shales and similar tight formations. At the current rates of production and exploration, there are more than 20 year of gas reserves in BC, reversing a previous decline, as shown in Figure 2.

British Columbia is ideally positioned to provide gas to North America with ready access to a number of major gas transportation pipelines including systems operated by TransCanada Pipelines, Spectra Energy Gas Transmission and the Alliance Pipeline. Many of these systems are undergoing significant capacity expansions to accommodate the influx of gas from these new plays.

This paper will explore the challenges posed to regulators in moving rapidly from conventional vertical well developments to unconventional multi-well pads consisting of multiple fracture stimulated horizontal wells.
The Potential for Slot Closure, Screen Damage, and Collapse of Liners in Thermal Horizontal Wells
Authors: O'Rourke J. C.
Published: February 2011

Liners in horizontal thermal wells do occasionally have production inflow problems and fail. Published literature exists on the risks and design issues related to the effects of thermal expansion on slotted liners in horizontal wells. This paper investigates two areas of liner behaviour that seem to have been somewhat overlooked. It examines: (1) the potential effects of thermal expansion or contraction on screened liners and (2) the effects of thermal contraction on slotted and screened liners.

Upon injection of steam, horizontal liners will expand or contract and be subject to compressive or tensile axial stresses. Whether the stress is compressive or tensile depends on when the formation closes in on the liner. If it closes in before the well is steamed, the stress will be compressive; if it closes in after steaming the stress will be tensile.

This paper examines the effects of shear force from the formation on the screens of liners both in expansion and contraction. It would appear that to some extent the shear or tearing forces on screens are self-limiting making them more resistant to tearing than might be expected.

The paper also examines effects on liners of tensile forces caused by contraction and cooling. Tensile forces on liners can approach and exceed yield under common operating conditions. The liners are then susceptible to slot closure and collapse.

Limits on operating conditions are presented to reduce the risk of such failures. Suggestions for further R&D on the subject are also made.
Characterization, Modelling and Simulation of the Fractured Najmah-Sargelu Carbonate Reservoir, Umm Gudair Field, West Kuwait
Authors: Matar S. , Ghilardini L. , De Groen V. , Le Maux T. , SinghaRay D. , Al-Shamali A.
Published: February 2011

The Najmah-Sargelu reservoirs of the Umm Gudair field in West Kuwait are tight, oil-bearing carbonate reservoirs in which production is mainly achieved through a well-developed multiscale fracture network. Developing such complex reservoirs implies the building of accurate matrix models, the fine static and dynamic characterization of fractures and the correct representation of both matrix and natural fractures into simulation models. In this paper, we present such a multi-disciplinary approach based on the integration of geological, petrophysical, geophysical, and dynamic data and where state of the art techniques in seismic characterisation, sequence stratigraphy, fracture modeling and simulation have been used.

The matrix model of the reservoirs was primarily developed based on the analysis of well data involving a core description and petrophysical interpretation. It was finalized by integrating the results of a detailed sequence stratigraphic analysis and a lithological characterization from seismic. The fracture characterization was based on the analysis of static and dynamic data and built upon the results of a former regional study. Large-scale fractures were identified with the help of seismic attributes and seismic facies map. Three sets of small-scale diffuse fractures were also characterized based on borehole image interpretations. Their occurrence is controlled by the shale content of rocks. Finally, the dynamic characterization of fractures using production data, well test and flowmeter data concludes on the critical impact of fractures on fluid flow in the reservoirs. Based on these results, a 3D Discrete Fracture Network (DFN) model of the reservoirs was built. It was calibrated against well test data in order to assess the hydraulic properties of fractures.

Both fine matrix model and fracture model were upscaled and combined to build a dual porosity simulation model. The history matching process enabled to better constrain both fracture network porosity and the matrix-fracture exchanges. It was then used to optimize the future development plan of the Najmah-Sargelu reservoirs. Classical production strategies such as depletion, water or gas injection were first tested. The type, number and position of new wells were then optimized.