bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Real-Time Optimization of a Highly Complex, Integrated Gas System: Intelligent Energy in the Real World
Authors: Göbel Derek , Briers Jan , De Boer Frank , Cramer Ron , Lai Kok-Lam , Hooimeijer Martijn
Published: March 2012

This paper describes the successful application of Real-Time Optimization by Shell Malaysia E&P on the Integrated Gas Production System in Sarawak, implementing models for real-time monitoring and optimization of wells and facilities on a gas production network spanning more than 100 wells on more than 40 platforms across a number of different Production Sharing Contracts. We highlight how Digital Oil Field practices enable field-based data to be turned into information, support decision making, and lead to actions that ensure production is optimized continuously.

The technology described in this paper is applied to achieve consistent gas supply to meet demand, maximize revenue, and enable improved and timely operational decisions - striking a balance between short- and long-term value, and taking into account the reality of commercial and contractual constraints, finance, and economics. The optimization is data-driven and covers more than 1,000 variables and features multiple, mutually dependent objectives and constraints.

The solution has proven significantly better than prior physical model-based solutions, which deliver optimized field settings, but with inherently unstable results, and not fast enough for application in a real-time decision making environment. Field trials have proven a result of: increased condensate production at current or improved expected Ultimate Recovery, whilst maintaining a stable gas supply, fulfilling quality constraints and contractual LNG nominations.

This is one of the first successful attempts to implement truly-real-time optimization in a production environment of this size and complexity, including a complicated set of commercial and contractual constraints, and striking a transparent balance between short-term and long-term value. Having proven that a multi-departmental reality can be successfully captured and modeled, might mark the start of a transformation towards embedding intelligent energy to its true potential.
Maximizing the Value of the Intelligent Field: Experience and Prospective
Authors: Alhuthali Ahmed H. , Al-Ajmi Fahad A. , Shamrani Sultan S. , Abitrabi Ballan Abdel N.
Published: March 2012

Our industry has embarked largely on implementing the intelligent field initiative in recent years, which is a clear indication of the surge to adapt to new methods, processes and workflows to manage existing and new fields. The capacity at which this technology was implemented worldwide is a sign of a strong buy-in from the industry that this technology will deliver on its promises in terms of maximizing hydrocarbon production, recovery, profits, or health, safety and environmental compliance.

Saudi Aramco is considered to be a leader in deploying and utilizing the intelligent field technology to maximize the value of hydrocarbon reservoirs. This paper discusses the implementation of intelligent field initiative in Saudi Arabian fields and particularly in the world's largest intelligent field, the Khurais complex. It highlights the huge infrastructure to measure and transmit data and to manage and control production in this field. As a result of the lessons learned from this experience, the classical reservoir management concepts are going through a major transformation to adapt to a fundamental change in data acquisition and production controls. Moreover, the engineers were faced with a new challenge in the reservoir monitoring process and overall field optimization, which requires a paradigm shift in analysis, interpretation, and decision making to maximize the value of the intelligent field. So far, the industry's efforts to utilize intelligent field technology are mainly focused at well level to optimize production rate and ensure target rate compliance. Saudi Aramco's efforts are going beyond the well level to optimize reservoir performance and enhance oil recovery. This paper illustrates some of those efforts, which resulted in a better understanding of well deliverability and reservoir connectivity.

In addition, this paper highlights the major challenges facing operating companies, to manage those fields. It provides methods and workflows to mitigate these challenges and maximize the value of intelligent fields and fully utilize the existing infrastructure and capabilities.
Innovative Work Scheme: Real Time Analysis During Well Test Operations
Authors: Ferreira A. , Vidal J. , Abi-Ramia R. , Jouti I. , Flores S. , Essenfeld D. , Cañas J. , Rey F. , Landinez G. , Maizeret P. , Villanueva G. , Cabanilla J. , Alves R.
Published: March 2012

In 2007, a new Independent Brazilian Oil and Gas company acquired 21 exploration offshore blocks, increasing its portfolio up to 29 blocks by March 2009. Ambitious exploration and production goals were set, such as Drilling Commencement by Q3 2009, Minimum Well Drilling Commitments in four Basins by 2010/11, Initial Development in the Campos Basin and First Oil by 2012. The first three initial goals have already been met and the fourth one is well online to be met as expected with the FPSO already in the Brazilian coast.

One of the key elements to reach these objectives is recognized to be the implementation of a focused innovative decision workflow, supported by a real time monitoring process from a cross-disciplinary Operations Support Center (OSC). This paper presents this innovative work scheme, based on a collaborative working environment between the operating and service companies during the well testing operations, with the most advanced monitoring and interpretation tools.

It includes a concrete field case which resulted not only in improved risk identification, prevention and mitigation, but also in operational performance optimization. This case was a horizontal open hole test of 1080 mts with 90 deg deviation. The real-time collaboration resulted in significant rig time savings, mitigation of unexpected events consequences, and delivery of higher productivity comparing similar wells results in the area.

This innovative decision workflow implemented in Brazil is considered as a high-technological reference model for operating companies, locally in Brazil and others around the world, to achieve success during challenging Well Testing operations.
Intelligent Energy and Other Industries - Lessons Learned
Authors: Strathman Michael , Lochmann Mark J.
Published: March 2012

If we have learned anything from the amazing gains and re-engineering that has occurred in exploration and other industries, it is that information technology, when properly applied, changes the rules of the game. Venture capital firms are always looking for companies that can secure a "first-mover" advantage because these startups offer the best opportunity for maximum returns. Those who move quickly to take advantage of new opportunities benefit the most. However, studies show that other industries are innovating much faster than exploration and production (E&P).

Manufacturing and process industries, such as chemicals, automotive, and refining, have all been forced to adopt new ways of working as a result of business imperatives or crises. Much can be learned by studying the challenges already addressed in those industries and assessing their applicability in E&P, particularly in production operations.

The capabilities of existing technology far exceed production operation's willingness to apply it today. It has been said that producers are in a mad dash to be second. They believe an early mover advantage is in reality a "first-mover" penalty. This paper will examine some of the pros and cons of a first-mover strategy for E&P companies.

It is a widely held opinion that our industry is unique and, therefore cannot use proven solution approaches and tools from other industries. Process and manufacturing industries have learned to look beyond their borders and have found that solutions can be reconfigured and successfully adapted to their businesses; they have replaced outdated problem-solving approaches with new ways of working. Oil and gas should be no exception.

Standard or enterprise-wide solutions and best practices assume a degree of commonality across assets, and this is assumed to be problematical in E&P. However, other industries contain assets with a high degree of variability, yet they have still overcome these barriers to innovation and rolled out common solutions.

This paper explores drivers, barriers, attitudes, and ways to apply important lessons from other industries to the upstream industry by comparing them to E&P to identify ways to make oil and gas operations more "intelligent."

The survey data shared in this paper is intended to highlight issues for further research and was not designed for statistically valid sampling.
Choices, Changes and Challenges: Lessons for the Future Development of the Digital Oilfield
Authors: Dickens Jeff , Feineman David , Roberts Steve
Published: March 2012

BP has had an active digital oilfield programme for over 10 years with our Field of the Future technology flagship. This paper identifies some key learnings from both our own experience and comparison with activity across the industry. We then examine the implications for the future of the digital oilfield concept.

In retrospect, we characterize BP's activities into two distinct phases. We believe the characteristics of these phases also apply more generally in the industry.

Phase 1 (2000-05) dealt with communicating a compelling vision and demonstrating the validity and potential of the digital oilfield concept. This phase dealt with engaging asset and major project teams in understanding the potential value in new ways of working by accessing real time operational information. In an R&D sense, Phase 1 was about developing and integrating a diverse set of tools to support technology trials and prove up the concept.

In Phase 2 (2005-11) we started to implement at pace and scale. For BP, the focus was on delivery of discrete real-time remote monitoring solutions and target driven value realization for well monitoring, surveillance by exception (i.e event driven rather than by routine scheduling), equipment reliability, and production optimization. We have documented value delivery of over 70 mboed net cumulative production impacts, plus other benefits. The choice of specific technologies was less important than the drive for sustainable implementation and solid business cases.

The range of industry experience raises an interesting question about options for the next phase of activity. These range from a focus on embedding the success to date as "business as usual", through to targeting the next class of difficult problems or operational risk reduction. Using the skills and experience from Phase 2 could unlock even greater value and further transform the work of energy companies.

RESULTS/CONCLUSIONS
Virtual Worlds-based Immersive Training Simulators for Improved Safety in Operation Start-up and Emergency Response Planning
Authors: Van den Wijngaert Hans , Lagae François
Published: March 2012

Growing offshore infrastructure complexity and capital investments, environmental and economic pressures and experience-age gap in technical workforce present unprecedented challenges to the oil industry. Technology advances positively impact immersive project reviews and enhance asset management practices, delivering new opportunities to mitigate some of these challenges.

Evaluation and rehearsal of emergency response procedures and in-context training of field operators for operation start-ups can now be performed in an intuitive game-like graphics environment, delivering high-value simulations and high-retention training sessions.

3D Immersive Training Simulator (ITS) provides scenario-driven training capability, leveraging the photo-realistic, real-time rendering of massive 3D VR industrial asset models.
The Development and Successful Application of an Automated Real-Time Drilling Fluids Measurement System
Authors: Stock Tore , Ronaes Egil , Fossdal Truls , Bjerkaas Johnny
Published: March 2012

The technically challenging development of the marginal resources in the mature fields in the North Sea requires new levels of planning and execution to control the drilling process.

Over the past few years, improved dataflow between drilling rigs and shore-based operator and service providers support organizations has created a renewed interest in automated monitoring of drilling parameters. Development of data transmission systems like InterACT and data formats like WITSML have initiated the search for and the development of new sensors that can be used for automated real-time monitoring of critical drilling fluid parameters.

Increased focus on HSE in general and the use of harmful test chemicals, vapors and the risk of explosions in particular also has been an important driver for this development. Introducing a level of automation described in this paper can reduce by 70-80% the exposure time of fluids engineer in the rig laboratory without compromising service quality.

Moreover, the development and use of advanced hydraulic simulation programs frequently employed for extended reach drilling and managed pressure drilling (MPD) have increased the focus on more reliable and more frequent operational inputs. The precision of modern simulation software represents a sharp contrast to the current practice of manual rig testing and reporting.

This paper details the selection of fluid parameters considered most important for automation. The authors will describe the sensors developed for monitoring the most important parameters, including Electrical Stability (ES), density, temperature, water content in invert emulsion drilling fluid, XRF elemental analysis, in-line particle size distribution (PSD) and full 3D rheology tests. The parameters that could be monitored with existing sensor technologies used in other industries will be discussed, as well as those requiring development based on current field equipment. In addition, the paper will describe the installation and first field experiences with a full range of automated instruments on various rigs in the North Sea.
Lessons Learned: Seeking Opportunity in Low Resistivity Upper Sihapas Sands in LA Field, Indonesia
Authors: Khresno Sri , Prakoso Ambaria , Kurniawan Akbar , Suderajat Suderajat , Nur Ilhami , Ontowiryo Bambang , Hermawan Rofiq
Published: March 2012

In formation evaluation, resistivity logs are typically used to identify pay zones because of the resistivity contrast between the oil zone and water zone. But not always. When the pay zone exhibits low resistivity, these logs cannot identify oil zones. LA field is a mature oil field in the Malacca Strait PSC in Indonesia that has been on production since 1984. Oil is produced from the Upper Sihapas (US) and Lower Sihapas (LS) sandstones. The LS sands have provided 98% of the oil produced to data. The US sands are thin, low permeability, low pressure and limited in volume (sand lenses) compared to the LS sands.

High water cuts in LS sands have made wells uneconomic to operate. Rather than abandon the wells, US sands were identified and re-completed alone (US sands will not flow when commingled with LS sands). But how to identify oil sands in the US? Resistivity of oil sands and water sands is almost the same. Gas readings and oil show give clues of oil in low-resistivity sands, but depth control is not accurate enough to know exactly which thin sand has oil.

The LA field has seven US producers. Production varies from well to well due to sand heterogeneity. We created a flowchart to determine oil potential, likely reserves and deliverability. Our experience is that low resistivity US sands can produce commercially at low water cut, albeit at low rate due to low pressure and low deliverability.
Pore Pressure Prediction in a Carbonate Reservoir
Authors: Atashbari Vahid , Tingay Mark
Published: March 2012

Knowledge of pore fluid pressure is essential for safe drilling and efficient reservoir modelling. An accurate estimation of pore pressure allows for more efficient selection of casing points and a reliable mud weight design. Current commonly used methods of pore pressure prediction are based on the difference between a ‘normal trend’ in sonic wave velocity, formation resistivity factor (FRF), or d-exponent (a function of drilling parameters) and the observed value of these parameters in over-pressured zones. The majority of the techniques are based on shale behaviour, which typically exhibits a strong relationship between porosity and pore fluid pressure. However, carbonate rocks are stiffer and may contain over-pressures without any associated influence on porosity. Indeed, the application of common pore pressure prediction methods to carbonate rocks can yield large and potentially dangerous errors, even suggesting absences or decrease in abnormal pressure in zones of high magnitude over-pressure. In some cases, the hypothesises which been in the conventional methods seems to be flawed in some cases where pore pressure decreases by depth.

In this research, a new method for effective stress calculation has been obtained using the compressibility attribute of reservoir rocks. In the case of over-pressure generation by undercompaction (as occurs in most clastic over-pressured sequences), pore pressure is dependent on the changes in pore space, which is a function of rock and pore compressibility. In simple terms, pore space decreases while the formation under goes compaction, and this imposes pressure on the fluid which fills the pores. A carbonate reservoir in a field in Iran has been investigated to establish pore fluid pressure generation mechanisms, and to attempt new methods for pore pressure prediction in carbonate rocks.
A Novel, Shear-Stable Fracturing Fluid for High-Temperature Applications
Authors: Kalgaonkar Rajendra , Patil Prajakta
Published: March 2012

Hydraulic fracturing often employs crosslinked polymeric gels, which are pumped into a subterranean formation with sufficient viscosity properties to generate fracture geometry in the subterranean rock and transport solid proppants to hold the fracture open. Crosslinking of a polymeric gel can significantly contribute to the success or failure of a fracturing treatment. Crosslinking agents used in commercial fracturing applications include borate, titanium, and zirconium (Zr) complex ions.

As the fracturing fluid is pumped downhole, it experiences different shears, such as high shear caused by tubulars, and low shear in the fracture. Typically, polymeric gels are shear thinning and will reduce in viscosity on application of high shear. The fracturing fluid's inability to shear recover as it transitions from a high shear regime in tubulars to a low shear regime as it enters the fracture can lead to compromising of near-wellbore (NWB) proppant transport and reduced fracture width, and treatment can screenout. Borate crosslinkers that are known to provide the shear recovery property to the fracturing gel typically have a temperature limitation of 300°F. Conversely, metal crosslinkers that have good temperature stability beyond 300°F are prone to irreversible shear degradation that does not reheal as the fluid passes from the high shear to a low shear regime, thus compromising efficient proppant transportation inside the fracture.

This paper presents the development of a novel fracturing fluid for high-temperature applications with a delay of complete crosslinking until after the fluid is beyond the high shear environment. Rheological characterization was performed with a Model 50-type viscometer at temperatures greater than 300°F, including shear-history profiles. The fluid chemistry presented employs a zirconium crosslinker and buffer combination that controls the crosslinker kinetics to yield a viscoelastic gel crosslink after passing through the high shear-history profile. Additionally, regained-permeability results obtained using conventional breakers demonstrated the fracturing fluid's cleanup efficiency.
Using Dynamic Simulations to Optimize the Start-up Procedure of a Lazy Horizontal Oil Well
Authors: Yusuf Rahel
Published: March 2012

During a well start-up, fluid distribution within the well shifts from a static segregated phase (gas-oil-water) column to a flowing three-phase mixture. For this transition to be successful, the well has to overcome the additional hydrostatic head associated with the phase segregation. This process can be problematic for wells with limited pressure support as an improper bean-up procedure can lead to a situation where the pressure driving force across the well is unable to overcome the hydrostatic head imposed by the liquid column during start-up thus resulting in a failed start-up. The failed start-up may add extra liquid present within the wellbore thus making subsequent start-up attempts even more difficult. For such wells, correct bean-up strategy is important to ensure successful start-up.

In the current work, dynamic simulations are conducted with a commercial transient-multiphase-simulator to understand the start-up flow and pressure transients and optimize the start-up procedure of a lazy horizontal oil well which has experienced start-up problems after a resting period.

Simulations of the failed bean-up procedure showed that a water-lock formation in the tubing hampers a successful well start-up as the hydrostatic head imposed by the water-lock does not allow the well to flow. An alternate bean-up procedure was then virtually tested by simulation where the wellhead choke was quickly opened. This led to a successful start-up as a gas pocket originally trapped in the horizontal section could escape to the vertical tubing only under quick bean-up thus lowering the hydrostatic pressure below the pressure driving force across the well. Dynamic simulations were also used to devise a strategy for the operator as to how long the well be rested before any bean-up is attempted. The proposed strategy enabled the operator to use the readings from downhole pressure gauge as a guide in deciding the resting period and bean-up procedure.

This study brings forth the significance of dynamic simulations in optimizing the start-up of lazy wells where failed bean-ups can lead to higher down times thus adversely affecting production. Further, dynamic simulations also help in arriving at guidelines for the operators on how to avoid failed start-ups.
A Coiled Tubing Perforating Solution Incorporating a Gun Deployment System and Dynamic Underbalance Technique Improves Well Production in High Angle Deep Gas Wells in Saudi Arabia
Authors: Al Jubran Hasan , Leal Jairo , Al BuHassan Shaker , Bolarinwa Simeon , Kharrat Wassim , Pulson Dave , Barnawi Mazen
Published: March 2012

Saudi Aramco has recently initiated a change in gas well design in the Ghawar field of Saudi Arabia. The new approach is to drill deviated cased hole gas wells through the reservoir to increase the length of contact of the productive zone and thereby increase production potential. Typical gas wells were drilled as a vertical cased hole through the reservoir or open hole horizontal gas wells.

The increased well deviations, measured depths and resultant increase in reservoir sections required a new approach to the perforating solution for these wells to connect them to the gas plants. Various techniques were reviewed, considering safety, operating efficiency and well performance. The final solution was to deploy the perforating systems on electric coiled tubing (CT) and run all the guns in one run using completion insertion and retrieval under pressure (CIRP) as a deployment system, which allowed the guns to be run and pulled under live well conditions without having to kill the well.

This paper details the learning curve and lessons learned from the implementation of this technique in five gas wells. The deployment system and pressure control equipment were optimized to satisfy Saudi Aramco’s requirement for three barriers. A CT cleanout run was added before perforation to remove any debris from the wellbore causing a problem to the depth correlation tools. An existing CT tower was used to support the very long wellhead stack, but due to its height limitation a special solution was implemented to enable safe CT operations. A deployment system under live well conditions was used to minimize CT runs, operating time and cost savings. The static underbalance condition was set before running the guns, combined with the dynamic underbalance perforating technique and deep penetrating charge gun design were implemented to optimize the well performance. This technique allowed safe and efficient perforating in a single underbalance run of these five gas wells.

The paper also covers the planning of the perforating solution, health, safety and environment (HSE) considerations, equipment selection, operational procedures, job execution and results.
Design of Gelled Fluid for Debris Removal in Subsea Pipeline
Authors: Misra Chaitali , Danait Achala , Salgaonkar Lalit
Published: March 2012

Transportation of hydrocarbon through a pipeline may be hindered as a result of deposition of debris. The presence of debris within the pipeline leads to reduction in the effective flow area, thus reducing the efficiency of the transportation system. Some of the factors leading to formation of the debris are changes in temperature and/or pressure of the transported fluid and chemical reactions which occur therein.

Pipeline maintenance pigging is routinely performed to extend the operational life of pipelines. Recently, a combination of mechanical and chemical remedial measures has shown beneficial results in pipeline cleaning. Mechanical brush pigs loosen the debris adhering to the walls, while chemical techniques, such as the use of gelled fluids, enhance the carrying capacity and help to transport the loosened debris out of the pipeline.

This paper presents the results of tests conducted to design a fast-breaking gelled fluid for a debris-removal operation in a long, large diameter subsea pipeline in the Asia Pacific region. In addition to exhibiting good stability and debris-carrying capacity under the laboratory test and field conditions, the gel had to be compatible and demonstrate stability when mixed with other additives in the transported hydrocarbon. A highly viscous, aqueous-based linear polysaccharide gel was designed to satisfy these requirements. A key environmental and operational consideration was the easy and fast disposal of the gel after completion of the cleaning operation. With oxidizing breaker, gels prepared in potable water resulted in viscosity of < 10 cp within two days, which was significantly shorter than when seawater-based gels were similarly treated. Preliminary field results indicate that the combined mechanical and gel system removed significant amount of debris. Data from future trials will help evaluate the feasibility of such technique for effective cleaning of the pipeline.
Development of a Fuzzy System Model for Candidate-well Selection for Hydraulic Fracturing in a Carbonate Reservoir
Authors: Zoveidavianpoor Mansoor , Samsuri Ariffin , Shadizadeh Seyed Reza
Published: March 2012

With current technology, it is only possible to extract 20% to 25% of the original oil in place from Iranian carbonate reservoirs, 10% less than the world average. In addition, formation damage is a serious problem in those reservoirs, which mainly caused by asphaltene precipitation, sand production, and ineffective stimulation method. The majority of mature carbonate reservoirs in Iran have low permeability and high skin values. Therefore, such reservoirs are capable of producing at commercial rates only if they are hydraulically fractured. Acid fracturing is usually reported as a standard method for fracturing in carbonate reservoirs. Hydraulic Fracturing (HF) technology, which was originally applied to overcome near wellbore damage, is a proper replacement stimulation method. It is evident that to adopt this technology, considerable efforts have to be strenuous in candidate-well selection. As asserted in the literature, even though a common practice, candidate-well selection is not a straightforward process and up to now, there has not been a well-defined approach to address this process. The techniques applied in HF candidate-well selection could be divided into two methods; conventional and advanced approaches. Conventional methods are not easy to use for nonlinear processes, such as candidate-well selection that goes through a group of parameters having different attributes and features such as geological aspect, reservoir and fluid characteristics, production details, etc. and that’s because it is difficult to describe properly all their nonlinearities. However, it is believed that advanced methods such as Fuzzy Logic (FL) could be better decrease the uncertainty existed in candidate-well selection. This paper presents a Mamdani fuzzy model where rules for HF candidate-well selection were derived from multiple knowledge sources such as existing literature, intuition of expert opinion to verify the gathered information. The needs for adapting HF as replacement stimulation in Iranina carbonate reservoirs are discussed and advanced methods for HF candidate selection will be reviewed in this paper. Also, the main reasons which show why propped HF is the choice in carbonate reservoirs will be discussed. Finally, the proposed Fuzzy system model is applied along with a case study in a carbonate reservoir.
An Approach for Spreadsheet-Independent Reserves Management Tracking, Archiving, and Reporting
Authors: Al-Sumaiti Hamad , Sethi Muhammad Usman
Published: March 2012

The tracking and management of both resources and reserves estimations are of primary importance for any oil and gas company. When managing reserves data using spreadsheets, organizations face numerous daily challenges in reserves tracking and reporting. This technical paper discusses the implementation and methodology adopted at one of the Middle East’s leading oil and gas companies for a reserves management system free from spreadsheet-based tracking and reporting. The resulting system provides much enhanced security and efficiency in managing reserves, and improves the flexibility of reserves reporting.
Hydrate Inhibition _ Optimization In Deep Water Field
Authors: Gupta Gaurav , Singh Sunil Kumar
Published: March 2012

Reliance Industries Limited operates D1D3 deep water gas field in Krishna-Godavari basin in India. Water depth at well heads varies from 550 meter to 1150 meter. Horizontal Christmas trees (XMT) are installed on each well head. Hydrate inhibitor is continuously injected at Christmas tree to prevent hydrate formation occurring in the system during all operating conditions. For a properly designed system, hydrate formation should not be possible in normal operation. The only risk of hydrate formation is related to abnormal operating conditions. Hydrate management philosophy should be developed to address the risk of hydrate formation in all condition with minimum hydrate inhibitor injection.

There are always some uncertainties in measurements therefore some level of hydrate inhibitor overdosing is required. In this field Mono Ethylene Glycol (MEG) is injected to prevent hydrate formation. To optimize MEG injection, reliable water and MEG measurements are the important keys. Salinity of slug, pipeline network and different well head water depths are major driving factors to optimize MEG injection.

Hydrate curve is developed either with professional software like PVTsim or rocking cell apparatus in laboratory. In this field minimum required MEG percentage is calculated from PVTsim software. MEG optimization is continuous process and since inception of field, the level of overdosing is reduced from 80% to 15%. Wet Gas Flow Meter (WGFM) is installed on each XMT to measure water production. To verify WGFM water measurement from individual well, other methods of measurement were also developed. MEG injection valves are installed on each XMT which can measure the injection quantity. Correlation is established between different measurement techniques to consider most reliable and accurate value of water and MEG measurement which aided to optimize the MEG injection rates.

Analysis is done through software for some of wells, to find out the feasibility to stop continuous MEG injection in deep water pipeline network system. After this study, continuous MEG injection was stopped in one well. The paper will describe various steps of MEG optimization and level of confidence on hydrate management philosophy.
Asset Integrity Management in Onshore & Offshore-enhancing Reliability at KGD6
Authors: Rao A. Rama , Rao S. S. , Sharma Tata , Krishna Karra Rama
Published: March 2012

In the life cycle of any asset during earlier days the majority of the focus was on frequently occurring incidents whose impact may be less, but the thought process has changed keeping in mind the recent incidents in the industry. The focus has now shifted to less frequently happening incidents whose impact will be substantial some times devastating.

The aim of this Asset Integrity at KG D6 is to develop the Hazards and Effects Management Process (HEMP), which identifies and assesses HSE hazards and potential risk, implements control and recovery measures, and maintains a documented demonstration that HSE risks have been reduced to a level that is As Low As Reasonably Practicable (ALARP).

In order to achieve ALARP level we identified to carry out many activities, with the help of number of systems, for which we are taking support of number of softwares, all of which are explained in coming pages.

Implementing the elements of Asset Integrity Management (AIM) has considerably increased the reliability decreasing the recordable incident rates. This has lead to "Thousad plus days" of uninterrupted gas supply without an incident.
Integrated Control System & Human Machine Interface – Challenges for Uninterrupted Onshore & Subsea Operations
Authors: Subbarao Mandava Venkata , Srinagesh Yerramalla
Published: March 2012

The health and effectiveness of any Integrated Control System depends on many factors. Among these factors is the proper design, selection of Control System, seamless integration, System Architecture, System Configuration, System Integration Testing, Control System Installation, Commissioning, Site Acceptance Test, Preventive Maintenance, Predictive Maintenance, Functional Testing etc.

The integrated solution for the Onshore, Offshore & Subsea Control System includes a dedicated Subsea Control System, DCS System, ESD System, Process Simulator System, F& G System, Large Screen Abnormal Situation Management Video Wall, Measurement Systems etc.

The power to the Offshore and communication to Offshore & Subsea is through Umbilical’s. The backup communication from Onshore to Offshore is through dedicated Microwave Network. The communication from Onshore Terminal (OT) Control Room to Subsea wells is about 50 Km to 60 Km. The remote Subsea wells are Controlled and can be Shut down from OT.

The best-in-class technologies in Control & Safety was effectively implemented by deploying various protocols like Foundation Fieldbus, HART, Control Net, OPC, MODBUS TCP I/P, Serial Interface etc. The digital Control System reliably monitors and controls the over 1, 10,000 tags. All the DCS hardware is integrated with the non DCS hardware while having a common control system information. The System has the facility to provide information across the organization giving the best possible foundation for collaboration between people, processes and systems.

In such a large network of integration of technologies & integrated operations of Subsea & Onshore, identifying and minimizing control system errors are a big challenge. It is a big challenge to ensure continued operations of these facilities without any Trips.

This article focuses on Control & Instrumentation Systems contributing factors for uninterrupted Operations of Onshore/Offshore/Subsea facilities during the first 1033 days of operations & the challenges to ensure continued operations without any facility Trips.
A Study of Differences in Array Induction and Multi-Laterolog Responses in a Well Drilled with High-Salinity Water-Based Mud
Authors: Corley Bill , Khokhar Rashid , Maurer Hans Martin , Li JianZhou , Xiao Dong , Yang ShaoKun
Published: March 2012

High data quality and improved environmental corrections of array induction logging tools have expanded their operating range into wells drilled with high-salinity water-based mud. Multi-laterolog tools are preferred for these borehole conditions when formation resistivity is high, but if the ratio of formation-to-mud resistivity is moderate, array induction tools can be used successfully.

A fairly large region of formation resistivity and formation-to-mud resistivity contrasts exists where you would expect either array induction or multi-laterolog devices to perform well. However, each responds differently to borehole effects, near-borehole effects, and invasion.

Data from both array induction and multi-laterolog devices was acquired in an offshore well from China with low-to-moderate formation resistivity drilled with high-salinity water-based mud. In some sections of the well the drilling assembly produced a "spiral" effect with small, periodic changes in borehole size. The majority of the well had no invasion but there was shallow conductive invasion in some permeable intervals.

The differences in sensitivity to shallow conductive invasion and the significant effect of a very conductive "spiral" borehole on the array induction responses is illustrated and explained by modeling. A filtering technique to eliminate the spiral effect and improve the responses is described and illustrated. The multi-laterolog tool has no sensitivity to the spiral borehole shape.

The determination as to whether an array induction or a multi-laterolog is the preferred resistivity device should be based on more than the value of formation resistivity or the contrast between mud and formation resistivity. In some conditions one has preference, while in other conditions it would be advisable to acquire both.
Gravel Pack Evaluation Techniques to Ensure Sand Control in Deep Water Unconsolidated Gas Reservoir
Authors: Dhar Samir Kumar , Bora Ajoy Krishna , Reddy Peesu Rathnakar , Mund Bineet K , Mishra Anoop Kumar
Published: March 2012

Effective sand control is extremely important for production of hydrocarbons from shallow unconsolidated sand reservoir. In absence of any sand control measure installed in the well, there is high risk of Sand production along with the hydrocarbons. Sand production may result in damage of X-Mass tree and/or Sub-sea infrastructure components. In extreme cases, when the sand production goes beyond the critical limit, it may lead to a situation when the field production has to be stopped. In view of this, in Deep water environment, sand production is considered as a potential hazard. It may lead to tremendous impact on reservoir economics and sustained production from the field.

The commonly used sand control technique is to install suitable sand screens and a packing of gravel at the sand face to restrict the movement of sand particles from the reservoir to the borehole. Gravel packing can be achieved through open hole gravel pack, cased hole frac pack or simply by lowering a pre-pack perforated liner/screen. Once the gravel packing is done, it is required to know the competency of the pack to confirm its effectiveness. Gravel pack evaluation is basically done from the data acquired by a logging tool conveyed either through wireline or wash pipe below the Gravel pack assembly run on the work string.

The techniques described in the paper were applied in deepwater gas reservoir consisting of thick unconsolidated sand and thin bedded sand- shale sequences. Wireline logging was done to evaluate the pack efficiency. In the absence of a single tailor made tool or technology, four different tools were used for this purpose with various advantages and limitations. Pipe conveyed memory logging device was also used for gravel pack evaluation in few cases. The results of all the methods were analyzed and an attempt was made to find a suitable cost effective technology for the evaluation of gravel pack. No Gravel pack evaluation job was included in the initial development plan by the operator, however as the operations progressed it was found to be essential especially in Deep water environment.

This paper describes the experience of the operator with different gravel pack evaluation methods and highlights associated merits and demerits. It also describes some specific cases where gravel pack evaluation became crucial for decision making and saved the production well.
Pre-fracture Treatment of Coal Seams for Fracture Conductivity Enhancement in Hydro Fracturing of CBM Wells and Coal Fines Mitigation in Multilateral CBM Wells through Wettability Alteration of Coal Fines - A Laboratory Study
Authors: Kumar Ajay , Roy D. C. , Yadav N. , Rao Y. R. , Singhal C. P. , Kumar Ajit
Published: March 2012

India has sixth largest coal reserves in the world and estimated to be at 206 billion tons and it ranks 10th in CBM resources having 4.6 TCM methane gas covers 20,000 km2 of area. The CBM reservoirs is multilayered, heterogamous, naturally fractured (cleats) and having fine micro pores. Bulk porosity of the coal is very small (<5%), the initial gas saturation is very low (<10%) and most of the gas in coal (>90%) is adsorbed in the micro pores of coal matrix and under saturated condition. Rapid dewatering is needed for reduction the reservoir pressures below critical pressure for desorption of gas from coal bed. Therefore, conventional / horizontal well with fracturing, multilateral well to cover many zones in CBM is being opted for economic exploitation. More than 60 no of conventional and horizontal/multilateral wells are drilled so far and many of them are completed with hydro-fracturing.

As coal is a weak substance and small pressure can cause the coal to fail and generate fines, hence enormous coal fines are normally produced during production (in case of high draw-down) and during hydro fracturing of coal seams. In some fracturing job, fines generation & migration reduces the fracture length and conductivity lead to reduced dewatering. Similarly, in multilateral well of CBM, coal fines are accumulated at the heel of the well in case of high draw drawdown and creating the restriction in dewatering and gas production.

In view of the above, innovative pre-fracture treatment technique with innovative formulation (Mixture Nonylphenoxy polythyleneoxide and Nonylphenoxy polythyleneoxide in the ratio of 1:2 with 0.5 % biopolymer) is developed & successfully tested in laboratory to change the wettability of the coal fine by making it hydrophobic to hydrophilic. Coal fines can easily come out with water based fluid during pre-treatment, hydro-fracturing and multilateral wellbore cleaning.
Tailpipe Disconnects Ideal for Setting Cement Plugs in Complex Wellbores; Procedures and Case Histories Provided
Authors: Rogers Hank , Poole David
Published: March 2012

The primary goal of operators and drilling contractors is to safely, economically, and efficiently drill more holes in less time to enable completion and production operations to begin. However, unplanned events that introduce unexpected and costly delays often occur during the drilling phase. These unplanned events must be dealt with in a timely and effective manner to enable drilling operations to continue.

One event type common to drilling operations is the need to set openhole cement plugs for plug back, kickoff, or curing loss-circulation intervals. The time and cost associated with spotting cement plugs directly impacts well operations and is often classified as nonproductive time (NPT) by operators, especially if initial plugs fail to achieve the purpose for which they were set. Placing cement plugs in today’s complex wellbores and the increased costs associated with these operations necessitates the use of plug designs and procedures that have been designed to reduce risk and utilize new technologies and documented processes to achieve the desired results. Reviewing current practices for deploying new technology helps to optimize overall plug cementing operations in both vertical and extended-reach wellbores.

However, there are a number of challenges associated with setting cement plugs in an openhole well. Most importantly, drillpipe can become differentially stuck across a lost-circulation zone, and the plug can become contaminated with the intermixing of the mud, resulting in inadequate isolation or insufficient strength.

An innovative tool (Rogers et al. 2004) has been designed to meet the challenges associated with setting cement plugs. The tool connects sacrificial/drillable tubing to the drillpipe and allows an operator to trip into the well and spot the cement plug across the problematic zone. Once cement is placed, the tool is disengaged and the operator trips the drillpipe out of the hole, leaving the cement plug and tubing undisturbed. The sacrificial tubing can be drillable; therefore, the operator can drill through the plug or commence other operations, as required.

This paper discusses the challenges operators face when setting cement plugs and how risks and NPT are reduced with this innovative plug-setting process and tool. Well examples are documented from case histories to illustrate the success and lessons learned.
Application of Microbial Treatment for Mitigating the Paraffin Deposition in Down Hole Tubulars and Surface Flow Lines of Wells- A Success Story
Authors: Biswas Susanta Kumar , Kukreti Vipin , Rana Dolly Pal , Sarbhai Munish Prasad , Bateja Surendra , Misra Tilak Ram
Published: March 2012

Severe wax deposition problem is encountered in down hole tubulars and at the face of producing zone in the well bore region and surface flow lines of most of the oil fields producing waxy crude. Paraffin in the crude begins to precipitate and deposit around well bore and tubulars as the pressures and temperatures decrease, frequently resulting into partial/complete blockage of crude passage and pose severe production problems. Traditional methods such as thermal, magnetic, mechanical scraping, and chemical treatment etc. are not only cumbersome, costly and hazardous but also provide temporary respite.

Use of microbes, a novel approach was conceived to find alternate effective solution. Institute of Reservoir Studies (IRS), ONGC, has developed two separate microbial systems for mitigating the vexed problem of paraffin deposition in oil wells and surface flow lines.

The microbial system for down hole tubulars comprises of paraffin degrading bacterial (PDB) consortium, nutrient supplements and growth enhancer. The bacterial consortium, is naturally occurring, micro-aerophilic, thermophilic, capable of degrading paraffin up to 90°C. Paraffin degrading ability was maximum at 55°C which is the temperature around which most paraffins get deposited.

The candidate wells having severe wax deposition problem, were selected from different fields of Mehsana Asset of ONGC. Application of the technology has been done successfully on commercial scale in 45 wells (48 jobs) of Mehsana Asset. The microbial treatment not only checked the paraffin deposition in all the treated wells but also improved oil production by 20-80% in many wells. Most of the treated wells flowed without any wax deposition for 6-8 months after the treatment. Some of the wells even flowed for over a year giving average success ratio of around 70%. Net incremental oil gain from 48 jobs was around 4000 m3.

Bacterial consortium, named as FIB-19, showing 67% wax degradation at 37°C prevents wax deposition in surface flow lines. The bacterial consortium is micro aerophilic, mesophillic and remains active upto 43°C. Application in surface flow lines of ten wells of Mehsana Asset was quite successful resulting in elimination of requirement of line flushing for considerable time along with reduction of pressure in the flow line.