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This paper summarizes the findings of the SPE Forum held in September 2005 on "Making our Mature Fields Smarter". Participants in the Forum have granted permission to present this paper on the basis that the authors are neither representing the views of the SPE nor of the participants’ companies. We are delivering smarter fields in order to add value to our business - there are many facets to this value beyond reservoir, well, process and production management. What may not be so clear is how to apply these smart technologies to mature fields with a legacy infrastructure and long production history. Participants felt that maturity in itself made a challenge for deployment and enforces the need for effective Change Management. Deployment and Change Management are seen as the major challenges facing the creation of Smart Fields. During the Forum it became apparent that companies do not have a common vision of what a truly Smart Field will look like and this contributes to the difficulty of assigning a value to "Smartness". There is a tendency to assign value to discrete technologies as opposed to the holistic full project value associated with the business process that has been improved by the application of that technology. The essential foundations for a Smart Field are: People and Skills, effective Data Management and Industry Wide Standards, appropriate Hardware and Systems Architecture. High quality data is a fundamental building block of Smart Fields and it needs to be treated as an asset, managed effectively with staff assigned to ensure the integrity of the data management systems. The key processes are built on this foundation and deliver the business result. These processes are supported by detailed workflows with corresponding enabling technologies. The business processes and workflows required to manage a mature field appear to be similar for many operators. The majority of the technologies that we require to create Smart Fields are already in place although we did identify seven specific areas where technology advances are recommended. Collaboration and visualization technologies are enablers and are required in order to integrate across the core business processes and permit people working with these processes to assimilate the huge and diverse volumes of data and information.

Starting from the idea that every activity can be improved in order to facilitated the safest working places, an effective risk management process requires a structured and systematic analysis method involving the Identification, Assessment and Control of hazards. In the same way the Recovery from potential events should be investigated and recovery measures analysed and prepared. The Petromar offshore operations in the Black Sea of Romania are a significant part of Petrom E&P. There is no legal requirement in Romania to provide a HSE Case for offshore installation. According to OMV group (the owner of Petrom) standards the preparation and implementation of a HSE Case is necessary. A key deliverable of this HSE Case was the purpose to make it electronically available for all the platforms and operational people to facilitate consistent use in the ongoing operations. OMV Petrom is committed to on-going improvement in HSE management; therefore HSE-MS in Petromar is effectively implemented with a continuous improvement in the management of all HSE hazards and effects that could occur in the workplaces. According to the HSE Case standard used in OMV/Petrom, the scope of the HSE Case is to: Deliver an integrated HSE Case to modern standards as seen in the international oil and gas industryProvide a comprehensive qualitative assessment of the hazards and current risk levels;Identify where improvements in control measures are required and areas where additional control measures (risk reduction measures) could be practicably implemented;Provide a reference document that defines the current position with regard to hazard management against which improvement can be demonstrated; andTo bring the common offshore and onshore Petromar HSE issues together in one document. The implementation of all these aspects is facilitated through the use of an electronic tool. This tool shows all the important aspects of the HSE Case; it has a user friendly interface and is easy to use. The tool provide a comprehensive qualitative assessment of the hazards and current risk levels; it identified where improvements in control measures are required and areas where additional control measures (risk reduction measures) could be practicably implemented and bring common offshore and onshore HSE issues together in one tool.

Well A (offshore field) was drilled in June 2002 to provide horizontal drainage point on the reservoir. It was completed as a Single String Single (SSS) Producer with 3 ½" tubing string. The sand face was completed with 5 ½" slotted liner (SL) with screen size of 300μm for sand control across 1, 505ft horizontal drain hole since the reservoir is unconsolidated. The interval started production in May 2003 and was closed-in for about a year for pipeline changeout due to pressure integrity before it was shut-in for security concerns. Thereafter the well produced uneventfully until sand production in excess of 10pptb (Pounds per thousand barrel) was observed. Various mitigation efforts were deployed however, all proved abortive. The platform tripped due to the rupture of the well choke body and this was traced to be caused by excessive sand production. The interval was subsequently closed in due to high sand production. Various options were looked into to determine the best solution that could be used to eliminate the sand production challenges, this ranged from insitu reservoir sand consolidation, horizontal gravel packing, rig re-entry to workover the completion and Thru-Tubing Sand Screen Insert to restore the completion integrity. However after various review sessions, Thru-Tubing Sand Screen Insert was recommended as the best option for the well because it was the most cost effective option, there are good premium screens and in-house expertise exists to aid its deployment. This was followed up with detailed sieve analysis of the produced formation sand and ditch cuttings for proper screen design. Furthermore, well modelling was done to predict the new well potential after the screen insert and was estimated at 2, 250bopd. In this paper, we present the technique utilized for rejuvenating a horizontal completion in July 2013. 500ft Techdaer-ENFORCER Premium Screens (230micron) was successfully spaced out with 900ft blank tubing and installed inside the top section of the 5 ½" SL and hung off on the production tubing with the Paragon Packer. This was achieved using a Coil Tubing mounted on an offshore Self Elevation Workover Platform (SEWOP) after the well was cleaned up and killed, making it a first in Shell Nigeria. Thereafter, production was restored at low sand cut of < 2pptb, at an average oil rate of 2, 400bopd since August 2013 till date, thereby safe guarding 2.5MMbbls of reserves and 2, 400bopd potential at acceptable sand production. Using a conservative oil price of $85/bbl, the total project cost which was $1.8Mln was recovered in 9days. So far the well has been on production since August 2013 with a cumulative oil production of 0.6MMbbl to date.

Abstract Thunder Horse is the largest production semisubmersible in the Gulf of Mexico with a displacement of 130,000 mT, while Atlantis is also a large semisubmersible with an 88,600 mT displacement. Both platforms are equipped with instrumentation to measure metocean and platform/riser response. This paper presents measured metocean data with comparisons to hindcast predictions. The measured platform and riser responses are also compared to analysis results using the measured metocean conditions. Both environmental and platform response (including mooring and riser systems) measurements have been recorded from the Thunder Horse PDQ and Atlantis PQ semisubmersibles. Several major hurricanes passed close to these two platforms since they were installed. This paper summarizes some of the key data measured in these extreme events. Data recording significant wave heights exceeding 40 ft and associated responses are included. Thunder Horse was installed in 2005 and thus was exposed to Hurricanes Katrina and Gustav along with several other hurricanes that did not pass as close. Atlantis was installed in 2006 and experienced extreme conditions in Hurricane Ike. Thunder Horse saw hurricane wave heights and current speeds exceeding the original 100-year design conditions with wind speeds just below 100-year design values in Gustav. It also experienced a severe post-storm inertial current for several days following Gustav. Atlantis similarly saw over 100-year wave heights and just below 100-year winds during Ike. Even though the metocean conditions exceeded the design values, no major hull, mooring or riser damage resulted. Comparison of platform response to numerical analysis shows that generally the actual response is less than the original predictions. It is not common to record real data in extreme storms. Valuable insight can be gained into the design assumptions and methodologies when comparing the actual response to design predictions. The results can determine how much conservatism is in the original design and can also have an impact on future FPS and riser designs. Such information can also be used to help assess the condition of the platform and post-storm inspection requirements. Introduction Both Thunder Horse and Atlantis experienced severe hurricanes in 2008. Hurricane Gustav passed 33 miles southwest of Thunder Horse and 79 miles northeast of Atlantis on August 31 - September 1, 2008. Hurricane Ike passed 66 miles southwest of Atlantis and 169 miles southwest from Thunder Horse on September 11 -12, 2008. The path of these two hurricanes relative to all seven of BP's floating production systems is illustrated in Figure 1. Due to the paths, Gustav was a more severe storm at Thunder Horse, while Ike was more severe at Atlantis.

Abstract BP's Thunder Horse and Atlantis completions are some of the most complex in the world. This complexity is both a basic requirement of the environment and a result of the desire to achieve as much functionality from a wellbore as practical. This paper will address the approach BP has taken to ensure " completions excellence?? on both the completion design and installation, but will not cover the design details of the completions themselves. Completions Excellence is a mindset of continuous improvement in organizational capability, planning, execution, and learning. Introduction Thunder Horse and Atlantis are two of BP's premiere deepwater (DW) fields in the Gulf of Mexico (GoM). These fields are in water depths of 5,500 ft to 7,000 ft and cover a number of OCS blocks each, so multiple drill centers and the use of state of the art dynamically positioned drilling/completion rigs is required. Well depths are in the range of 19,000 ft to 28,000 ft MD. Reliable, high-rate well completions are critical for the success of these fields. Complex reservoirs with multiple stacked pay sands result in wells that typically require multi-zone sand control completions. A typical Thunder Horse or Atlantis completion may cost tens of millions of dollars and the completion itself will account for one-half to two-thirds of total well cost. Production from such wells may be over 50 thousand barrels per day. Initial completion designs were single and stacked cased and perforated or frac packed completions, but in order to improve capital efficiency, downhole flow control was added to better manage the reservoirs and minimize future interventions (Figure 1). The complexity of even the simplest DW GoM completions mean that any engineering or installation errors can cost tens of millions of dollars to fix, and that major workovers can be even more expensive. Despite all the complexity, most of the problems encountered in delivering these wells have involved getting the seemingly minute, simple details right. Things like O-rings, metallurgy and unforeseen sources of debris have led to some of the biggest challenges. A successful completion is the culmination of getting thousands of small details right the first time through a system of checking and re-checking during design, manufacturing and assembly in the shop; and again in the field prior to and during installation. There is no doubt that to achieve completions excellence " the devil is in the details!??

Abstract Start-up and superior operational performance of the Atlantis and Thunder Horse deepwater developments represent historic achievements for BP's Exploration & Production business. This success is manifested in the plant operational reliability demonstrated and expanded upon within the scope of this paper. The Atlantis and Thunder Horse teams attribute this accomplishment to the factors within the following broad categories: Major Project Integration, Operational Readiness and Start-up and Overcoming Adversity. As of end 2009, Atlantis delivered an operational reliability of over 98% and Thunder Horse delivered about 96%. Perhaps the greatest benefit is that all the concepts outlined in this work can be applied to future developments throughout the oil and gas industry. Introduction The successful development and production start-up of each of the Atlantis and Thunder Horse projects represent historic achievements for BP's Exploration & Production business. The two ultradeepwater semi-submersible facilities stand as groundbreaking megaproject deliverables in the industry given the size, scale and technological frontiers surpassed in their successful handover to operation. Even more impressive, though, has been their performance since that handover and the first oil dates (October 6, 2007 and June 14, 2008, respectively), ramping-up to today's production rates where they are safely and reliably delivering over 350 MBOE cumulatively to market every day. Plant operational reliability is the specific measure of success which the Atlantis and Thunder Horse organizations utilize when considering the efforts in the lead-up to first oil. Industry definitions of operational reliability can vary. Both Atlantis and Thunder Horse utilize the definition offered by the BP Production Efficiency Improvement (PEI) Common Process to continuously review plant performance. PEI is a common BP operations framework; one of its outputs is a quantification of Plant Operational Reliability. This reliability value is calculated using the following formula:Equation * IPC: Installed Production Capacity; Total production capacity that the combination of available wells, subsea, topsides and export systems are able to deliver to sales at any point in time. Atlantis and Thunder Horse have achieved greater than 95% reliability (using the above definition) since each delivered first oil. This fact has been a product of a number of notable endeavors which commenced from project inception and onwards through to execution and operation. These range from the areas of major project integration, preservation, operational readiness planning, start-up execution and systematic day-to-day operations from " Day One.?? The success was also a product of the way in which Atlantis and Thunder Horse responded to adversity and technology challenges posed by these frontier developments, creating valuable industry experiences through the lead-up to first oil, start-up, ramp-up and normal operations to date.

Safety culture is now recognized as being a significant influencer of safety outcomes within the workplace. However positively changing safety culture has proven to be a bigger challenge than expected in many organisations. If current strategies and initiative have failed to have the impact that was desired, perhaps it is time to discard them and explore other options. Using a traditional safety model where the physical environment, systems of work, and personal behavior all interact to impact on safety outcomes, this paper takes a a unique approach to revamp and reorganize this model in a pway which identifies the key drivers and outputs required. What emerges is a very practical and logical model that clearly shows the various strategies that should be focused on in the areas of safety control (safe environment), safety management (systems of work) and safety leadership (safe behaviours). With reference then to safety culture being an influencer of safety in general, and safety culture being directly affected by the safety attitudes of personnel, then safety leadership becomes the key driver for change. Safety leadership is something that everyone already does. Effective and positive safety leadership on the other hand requires a safety thinking mindset, and then the application of leadership skills such as leading safe behaviours, coaching safety thinking and rewarding positive safety behaviors. In addition, some strategies that appear to be safety focused may in fact be harming safety culture. These include the recording and measurement of incident data, the use of safety slogans, and in particular the use of "zero harm" terminology. Organisation should consider discarding these strategies.

This manuscript is submitted as an addendum to SPE/IADC 797971, which discussed emerging successes using a new fixed cutter bit to drill hard rock applications conventionally drilled with roller cone bits. The new bit design using thermostable polycrystalline (TSP) diamond cutters and stability enhancing features has produced results, particularly in the Carthage field in Panola County, which are revolutionizing hard rock drilling in several areas of East Texas. The paper focuses on how teamwork, selective testing programs, and product improvements have combined to create step change improvements in hard-rock drilling capabilities. The paper discusses new information on optimal operating parameters and includes case history examples.

ABSTRACT This review paper describes the status of developments towards a complete set of international standards for the oil and natural gas industry. It builds on papers describing the intent of the program me presented at the 1992 OTC by Thomas, Thorp and Denham; Wilson; and Arney (Refs. 1, 2, and 3)(Available in full paper). These papers state the objectives of developing a set of ISO standards predominantly within lSO/lC67. This paper places the development of the set of standards for the oil and natural gas industry in the context of the need for, and use of, standards by the industry. It describes the main standards organizations including their structure, procedures and relationships. it identifies lSO/TC67 as the key international standards committee for "materials, equipment and offshore structures for petroleum and natural gas industries", and details its role and current work programme. It concludes with a summary of the achievements to date. Significance: Common international standards should enable all stakeholders involved (users/ suppliers/ regulatory bodies) to conduct their business efficiently (Iifecycle cost) with enhanced safety/integrity. INTRODUCTION Standards are generated and maintained with the specific aim of providing a means to:enhance technical integritytransfer knowledge, andcarry out business efficiently and cost effectively. With a system of standards in place which clearly and transparently specifies common essential requirements it is possible for a company to practice "Variety Control": i.e. restricting the number of types and vendors of equipment and services meeting the requirements (Figure 1)(Available in full paper). Several oil companies have developed standardization policies aiming to (Ref. 4):maximise the use of external standards;minimise additional requirements in company standards;ensure variations are justified for both technical and commercial reasons;ensure the continuous improvement of company standards by feedback from users of the standards; andpositively influence external standards bodies to increase the number and quality of external standards applicable for company use. (Note: In this paper company standards include company specifications). Typically, the following headings need to be addressed in order to successfully create and maintain a company standards system: steering committee; transparent standards structure; company standards development; external standards participation; enhanced use of information technology; variety control; and training. A transparent standards structure is illustrated in Figure 2. This reflects the policy statement, for a large organization, and recognizes the principle that operating company variations and project variations to the company and/or external standard exist and may be required. Inherent in the transparent standards structure is an enhanced commitment to external, preferably international, standards. BACKGROUND The oil and natural gas industry is international in its operation, with many large oil companies and their suppliers operating all over the globe. The oil and natural gas industry uses a great number of standards developed by a range of organizations including industry associations, and national, regional and international standardization bodies.

Electrostatic coalescence is the most efficient water-in-crude-oil demulsifying technology having been adopted in upstream dehydration and downstream desalting operations. Significant improvements in the capacity and performance of existing crude oil dehydrators/desalters have been achieved through continuous improvement in the mechanism research, the electric field development, and the practice of pre-coalescing step.The first part of this paper presents the current understanding about the electrocoalescence mechanism of water droplet in crude oil emulsions up to now. Besides analyzing various forces acting on the water droplet at a macro-scale, it also discusses the influence of turbulent flow conditions and electric field voltage/frequency.The second part of this paper presents systematically some typical technologies in electrostatic demulsification process and online electrostatic pre-coalescers up to now. For the electrostatic dehydrator/desalter, the authors pay more attention to the composite plate electrode, PC-based Load Responsive Controller, improved feed-stream distribution and variable voltage/frequency electric field. The variable voltage/frequency technology is the tendency which makes it possible for the customer to adjust the voltage and frequency simultaneously according to the corresponding physical properties of the inlet crude oil stream, thus the dehydration efficiency will definitely be improved. The typical representatives of compact electrostatic pre-coalescer which have achieved successfully field trial results, such as CEC, IEC, VIEC, highlight the moderate turbulent flow in their corresponding proprietary technologies, rather than the power supply.Finally, some technological tendencies related with electrostatic coalescence of water-in-oil emulsions have been presented, such as integration with centrifugation, combination with flotation, etc.. Considering that heavy oils are becoming increasingly attractive from the stand point of reserves and economic status including China, the authors introduce the challenge and some successful trials on the electrostatic dehydration of heavy oils. Some suggestions are put forward as concluding remarks.

Abstract Generating steam with an oil field water containing high concentration of total dissolved solids (TDS as sum of total ions) and high silica was tested at 1200 psi in the Wilmington Field in Wilmington, California. This work was during 1990 and 1991. Waters with total hardness of 1000-2300 ppm as CaCO3 with 200–300 ppm silica and TDS of 10,000 and 28,000 were treated with conventional strong acid and weak acid softeners. The steam was generated in a small 1 MM Btu/hr steam generator at 75% and 70% steam quality respectively. Besides obtaining operating costs to compare with previous laboratory and field data, this pilot was to confirm on a larger scale, laboratory data that high TDS, high silica waters could be used in steam generation without silicate problems if the hardness and the iron level were controlled to low levels. Our previous experience had indicated that a low iron level was not controlled in most steam generation using recycle produced waters which resulted in silicate problems, sodium iron silicate or acmite. Other softener pretreat systems such as hot lime, caustic, and steam stripping were considered or tested and would need to be considered for a large installation with water of this high hardness. A patent on using steam stripping as a pretreatment has just been issued as the result of associated pilot testing. In water softening, TDS is usually the sum of the cations or anions as CaCO3 but in this paper TDS is the sum of all the ions except sulfides unless otherwise noted. Introduction During the time of water shortage in Southern California, Union Pacific Resources, Inc. had an 80 MW cogeneration unit which used fresh water from L.A. Metropolitan Water District. The steam from this cogeneration was injected into a 2600 foot steam drive at 1200 psi. The formation had previously been waterflood and the reservoir water was about 28,000 TDS. The return steamflood produced water dropped to about 10,000 TDS in about three months and remained relative constant throughout the steam flood. Several options were considered, including tertiary treated sewage water, fresh water from sea water, use of underlying fresh water sands which were downdip of the injection barrier of L.A. Metropolitan Water District, purchasing unused water from other water districts, and recycle of the produced water. All were pursued simultaneous as the economics clearly favored tiny of the fresh water choices. It was estimated that if 10,000 TDS water were injected, the return water TDS would increase, but still be an acceptable alternate. Recycle of produced water has been done by operators in the Bakersfield, Taft and Coalinga area as well as Canada for years. The main Bakersfield area recycle water is fairly fresh water, 2000 TDS, although it can contain high silica. Hagist etc. and Hagist provide good general summary papers on treatment of water for oil field use. In 1967 Hagist reported the injection of 300 ppm silica into a steam generator water and indicated no deposition. There has been numerous cases of silicate deposits in the various recycled waters but most of these can be traced to hardness upsets or high iron levels in the feedwater. Some recycle has also been overseas in steam floods. For example, we participated in the 1986 field tests in Oman, (Rice), where steam was injected at 2200 psi from waters between 5000–14,000 TDS and 1500 ppm hardness as CaCO3. Silica content was low in these waters but soluble iron was high and resulted in some sodium iron silicate evaporator section problems prior to installing iron removal equipment. This water was conditioned by the use of strong and weak acids softeners. Preliminary Resin Tests The resin capacities of both strong acid and weak acid for the various TDS waters are known with in various ranges based on our own previous experience plus the large amount of work published concerning recycle of steamflood and caustic flooding. P. 143^

The growing demand for well-designed weighting agents to overcome the currently drilling challenges such as ECD management and the settling tendency of the weighting agents led to the development of a new micronized ilmenite (FeTiO3). The acid solubility of ilmenite is of great importance to remediate any damage that might occur during its use in the drilling operation.Extensive lab work was conducted to: 1) assess the reaction of 10 wt% HCl with ilmenite particles at 300°F and 300 psi using an aging cell, 2) optimize the concentration of HCl to remove the filter cake using a modified HPHT filter press at 250°F, 3) determine the removal efficiency of the filter cake, and 4) calculate the retained permeability of Indiana limestone cores.The reaction of hydrochloric acid with ilmenite showed that HCl (10 wt%) dissolved 75 wt% of the iron from ilmenite particles after 10 hrs of reaction at 300°F. SEM and XRD results showed that the reaction product was mainly rutile (TiO2) after 6 hrs of reaction.Ilmenite-based filter cake was removed completely after reaction with 5 wt% HCl (300 g solution) for 16 hrs soaking time at 250°F. The retained permeability of the Indiana limestone and Berea sandstone cores was nearly 100% after HCl treatment (5 wt%). Removal of ilmenite water-based filter cake is a simple process as compared with barite water-based filter cake, which cannot be removed using HCl. This study will provide a complete evaluation of the reaction of HCl with ilmenite and will help the drilling and completion engineers to better design the chemical treatments to remove the filter cake for HPHT wells.

Over the past several years shallow gas reservoirs in southern Alberta have often been fracture-treated utilizing a blanket design, with the primary objective of minimizing completion costs on these marginal wells. Strategies such as simplifying logistics to take advantage of economies of scale, and reducing fluid and gas requirements have been successful in achieving this objective. This paper discusses a pilot project, which examined ways to enhance the economics of both the Medicine Hat and Milk River formations. The ultimate goal of the project was to improve overall economics by increasing production, rather than relying solely on reduced costs. Successful trials were to provide justification for future down spacing of the field. The impact of varying the ratio of liquid CO2 relative to base fluid in twelve wells was observed. Initial production results have proved exciting and strongly suggest the possibility of doubling production rates in the long-term.

Abstract In this paper, the structure, conduct and performance of the West Virginia natural gas producing performance of the West Virginia natural gas producing industry is discussed. The competitiveness of the gas industry is measured empirically using the concept of concentration ratio and other features of industry structure. Trend analysis of the industry activities and outcomes shows no evidence of "market power" among West Virginia gas producers. The general drilling trends in West Virginia paralleled those of the entire U.S. Similarly, the trends in new gas discoveries, real wellhead price, gas exploratory drilling, to a large extent, are closely related. It was noted, however, that oil and gas operators in West Virginia took less risk in exploratory drilling between 1981-1987. It would appear that more exploration activities must be undertaken to reverse the current downward trends in new reserve additions in the 1990s. Introduction The development and utilization of natural gas resources from "in situ" deposits to end-users follow four sequential economic phases. These phases of natural gas development represent different aspects of a rather complex industry. Each aspect is a distinct, yet an interdependent economic stage with different regulatory environments and market conditions. The economic analysis conducted in this paper is focused primarily on natural gas exploration and production stages of the West Virginia natural gas production stages of the West Virginia natural gas industry. The exploration phase represents the supply aspect of the field market, and the production stage depicts the demand aspect. The exchange commodity is new gas reserves. The analytical framework used in this paper is based upon the concept of concentration ratio and other key characteristics of industry structure— those features of the business firm that conditions the firm's behavior. First, the concept of concentration ratio is operationally defined. Second, other key indicators of industry performance are evaluated to determine the existence/presence of any anticompetitive behavior among oil and gas producers in West Virginia. An investigation of the implication of vertical integration on gas resource accessibility, extractive capacity, and production outlet is conducted to detect any evidence of absolute monopoly power for integrated gas operators in the state. Finally, a market analysis of new natural gas reserves is performed. The key factors, market determinants and performed. The key factors, market determinants and exchange commodity in the reserve market are identified and examined. WEST VIRGINIA NATURAL GAS PRODUCING INDUSTRY The West Virginia natural gas producing industry is characterized by many small and middle-sized operators. Approximately 90-95% of industry activity in West Virginia is done by "independent" producers. The extent of industry competitiveness may, however, be ascertained empirically using the concept of concentration ratio and other elements of market structure. The concept of concentration ratio has been operationally defined as the percentage of assets, value added, or output accounted for by a specified number of the largest companies in an industry. The higher the concentration ratios for the top four or top eight companies in an industry the greater the monopoly power. In Table 1, the concentration ratios presented are defined in terms of cumulative exploratory footage drilled, cumulative completed wells, and accessibility to remaining petroleum resources. The reported activity for the top four and top eight oil and gas operators in West Virginia covers the period between 1977 and 1987.Table 1 shows that drilling and production activities in West Virginia have become less structurally concentrated. P. 197

Facultative thermophilic microorganisms were isolated from oil and water samples from Malaysian oil wells. The isolated microorganisms grow in an enrichment medium containing kerosene (hydrocarbon) as the source of carbon and energy. Batch-growth kinetic studies were carried out in a 500 ml shake flask and the production of biosurfactant and biopolymer were found to be cell growth associated. Two of the isolated microorganisms (S24A and S21A) are capable of producing biosurfactant in sucrose and glucose containing medium. These are indicated by the reduction of interfacial tension (IFT) of the supernatant. These two strains obtained the IFT reduction in both sucrose and glucose medium for more than 20 dynes/cm. Strain S19 and S12A can reduce the surface activity of growth medium only in sucrose and glucose medium respectively. Strain S19 can reduce the IFT of sucrose growth medium for 25.27 dynes/cm and no decreased in surface tension and interfacial tension were observed when S19 was grown in glucose medium. Adversely strain S12A can only reduce the IFT of glucose growth medium for more than 30 dynes/cm. Another two isolated bacteria was found to produce biopolymer and increase the viscosity of supernatant from 1 cp to 4 cp are strain S13 and S17A. These isolates produce exopolymer like material when grown on agar medium containing 5% sucrose.

Historically, enzymes have been used in the oil industry both for improving the characteristics of a range of biopolymers employed in the industry and as breakers for biopolymer gels. Until recently, the use of enzymes downhole was limited to gel breaking applications where suitable enzymes are used to break down or degrade a specific gel. In this case, the enzyme is used to remove a chemical which is no longer required, such as biopolymers in filter cakes following drilling or in tracing gels after the frac has occurred. More recently, enzymes have been used to produce useful chemicals in-situ. An enzyme-based method has already been reported which generates organic acids for a variety of acidizing applications such as matrix acidizing, the stimulation of natural fracture networks, damage removal over long horizontal intervals or gel breaking. The generation of acid in-situ following placement of the fluid ensures the even delivery of acid over the whole of the treated zone. The use of enzymes for generating useful oilfield chemicals has now been extended. Examples in the use of enzymes for the in-situ generation of minerals, gels and resins with potential for use in applications such as water shut off and sand consolidation are now reported.

A surface hole diverterless drilling method, utilized on a jack-up drilling unit, has been successfully implemented offshore East Kalimantan, Indonesia. Variations of the diverterless drilling method have also been utilized on 72 wells drilled from platform and floating drilling units offshore East Kalimantan. The diverterless drilling method provides an enhanced risk management tool superior to conventional offshore surfacc hole drilling. This method maximizes personnel safely and minimizes risk to property and the environment. The method also provides an ancillary cost savings. The evolution of the diverterless drilling method, the practical application for jack-up implementation and the benefits of diverterless drilling are detailed herein.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 49th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Texas, Oct. 6–9, 1974. Permission to copy is restricted to an abstract of not more than 300 words. illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Injectability of biopolymer produced by the organism Xanthomonas produced by the organism Xanthomonas campestris can be significantly enhanced by the use of proper mixing techniques, adequate surface preservation from microbial attack, preservation from microbial attack, and the use of clean bacterial-free injection systems and source waters. An evaluation of filtration and clarification methods and costs has shown that large reduction in the number or size of cellular material can be obtained at minimal costs. Introduction Solutions of the microbial produced biopolysaccharide Xanflood have been studied in several field and laboratory situations to test their effectiveness as mobility control agents. It has been demonstrated that once in the reservoir Xanflood provides excellent mobility control providing certain surface treatment requirements are met. In both field and laboratory studies where the surface treatment of the Xanflood solution has been inadequate, wellbore impairment and reduced injectivity have raised questions concerning the suitability of the biopolymer for use as a mobility control agent. Examining the method of fermentation of the biopolysaccharide and microbial studies have shown the presence of bacterial cells included presence of bacterial cells included with the biopolymer during the manufacturing process. Microscopic measurement of these cells has shown dimensions of 0.3 to 0.5 micron on diameter by 0.7 to 2.0 micron length. Coulter data reported by Yost and Stokke apparently confirm these dimensions. Patton has postulated the existence of undissolved biopolymer clumps or aggregates in solution. Laboratory experiments have also shown that cellular material included with the biopolymer can provide a nutrient source for microbial growth in solutions of Xanflood which must be controlled to prevent wellbore impairment and in extreme cases degradation of the biopolymer. The existence of microgels in biopolymer solutions and the cross-linking phenomenon with di and trivalent ions and certain complexes of boron have been seen which have a definite effect on the ultimate injectability of the polysaccharide biopolymer.

There are several challenges when establishing a multi-rig operation in a new drilling or workover project. People from different companies and diverse backgrounds will have to work together and integrate with each other in a new working environment. These challenges are compounded when the drilling contractor is new to the country, rigs are newly built and ‘linguistic differences’ impacting efficient communication that exist between the staff of the drilling contractor and the project team. This paper reviews the start-up and the learning curve for a project of four rigs to drill horizontal and vertical wells under LumpSum TurnKey (LSTK) contract. It presents the measures implemented to create a cohesive team and to accelerate learning. Also, it focuses on rig management, safety assurance and performance driving and monitoring. The main challenges are highlighted, and the step by step solutions taken are described. The results discussed are showing the progressive improvement from a quality and safety standpoint. Drilling data from over 100 wells is analyzed to illustrate how workflows and innovative technologies contributed to progressively improve well delivery and surpass the established benchmarks. Finally, the paper discusses the merits of integration between the client, service companies and the drilling contractor, presenting a clear case where the whole is greater than the sum of its parts.

Several factors like maturing oilfield, difficult market conditions, etc. are driving E&P companies to attain operational excellence (OE). OE basically requires running operations safely, reliably, sustainably, and cost effectively with a competitive advantage. Preventive Maintenance (PM) has great role in preventing failures, and thereby, it is a key but often ignored in OE discussions. Conventional PM practices are prone to limitations that may negate the fulfilment of requirement of OE. This paper presents a novel approach of conducting PM activities, namely Zero Shutdown (S/D) Philosophy that offers benefits towards fulfilment of all elements of OE. Conventional PM practices are very expensive and aggravates risks on many counts. Usually, PM is carried out, on fixed intervals, by shutting down entire production facility for long duration (e.g. 42 days). Such S/D causes several problems for an operating company, including the lost production worth billions of dollars. Sense of urgency to finish the entire PM activities in limited time makes it an extra- ordinarily risky mega project involving extra-ordinary mobilization of resources. Numerous different activities happening simultaneously in the same area crowded with large number of work-force and machines, with a time-pressure create additional risks. Further, despite such huge investment & efforts, the risks of uncertainty prevails in successfully completing the scheduled PM because unexpected condition of equipment-internals may require actions that are not planned but require long lead-time. Also, deferring PM activities simply on shutdown schedules, instead of identifying the risks and taking prompt actions, jeopardising the benefit of PM. In both cases, risks of high consequence failures always looms there in view of deferring the PM to next schedule after several years. Recognising the importance of risk-based inspection and reliability-centred maintenance, and to overcome above kind of limitations of conventional PM practices that cause bottlenecks for OE, a paradigm shift was made from the conventional PM practices. It was conceptualised to conduct all PM activities without shutting down the entire plant, through appropriate planning and by incorporating necessary provisions in the plant. This philosophy, herein, is termed as Zero S/D PM Philosophy, and the paper narrates the transitioning from conventional PM practices to adopting Zero S/D PM Philosophy in Kuwait oilfield, and provides guidelines to attain stepdown procedure for implementing Zero S/D philosophy. The above mentioned Zero S/D philosophy was successfully implemented for several KOC facilities, and the outcome were found quite beneficial, which shall be discussed in the paper. This paper promulgates the revolutionary zero shutdown PM philosophy that contributes to OE, and provides guidelines for implementation and disseminate lessons learnt, and best practices regarding PM activities. This also embodies goodwill contribution for betterment in the GCC region, while advancing together with excellence. OE basically requires running operations safely, reliably, sustainably, and cost effectively with a competitive advantage.

The importance of improving the drilling performance in an E&P company cannot be under estimated as it directly impacts the overall cost of the project. The objective of drilling and well engineering management system is to address the technical and organizational aspects of Drilling operations and deliver the wells in safe and cost effective manner. The different tools that are the vital part of the Drilling and well engineering management system include gates review process for well delivery; section-wise after action review, lesson learned tracking system and non-productive time(NPT) tracking system for continuous improvement from the previous wells. Tools for knowledge and data management and analysis (including technical limits& field specific KPIs) and their input for the upcoming wells is also the part of the system. A cross deliberation, peer review process and auditing system is in place in the process for the compliance check. Notable impacts of the Drilling well engineering management system include rigorous well examination during the gates review process, enhanced risk assessments of various aspects of well planning. The system provides accurate and detailed monitoring of the drilling operations through various tools during the execution phase. Within one year of its implementation, the operator was able to improve the drilling performance by achieving huge benchmarks in exploratory and development prospects across the entire operated blocks. In some of the fields, where the drilling activity is progress for more than 50 years; the implementation of the management system provided around 100 to 150 % decrease in drilling time and cost in the benchmark wells. This paper includes the results from one of the major challenging fields; Adhi field in which subject changes were implemented successfully. This paper provides an overview of the management system, its implementation in the organization and outcomes and benefits achieved in the drilling efficiency through the system.

The objective of this research paper was to explore the health, safety, sustainability and social responsibility during disposal of cutting and drilling fluids in Kenya in regard to what affects the choice of method of disposal, the Kenyan government's regulatory requirements on disposal of the drilling wastes, methods of addressing drilling wastes, ways of reducing the volume of wastes, hierarchy of drilling wastes and the pros and cons of various methods of addressing drilling wastes. A comprehensive case study of the approach taken in Kenya with regard to handling of drilling wastes was done. Description for each approach used is provided as obtained through interviews, internet and questionnaires and statistics. Complete tables and graphs are provided and the methods are described in detail to permit readers to understand all results. The choice of method of disposal is determined and affected largely by the government policy and also by economic, technical and operation conditions and barriers. Methods of disposal included injection, thermal treatment, bioremediation, land application. This paper gives the best ways of disposal. A comprehensive description of the Kenyan government regulations is given as indicated in the Kenya Gazette, NEMA and UNEP. This paper gives insight to the acceptable drilling wastes disposal practices in Kenya and are also generally largely applicable other nations. In conclusion, it was found that Kenya would benefit from passing its own laws to regulate disposal in the coming days.

Application of Managed pressure drilling (MPD) technology with other techniques to maintain constant Bottom Hole pressure (BHP) has been found to enhance drilling operations in applications where the margin between the pore pressure and fracture gradient is narrow and the reservoir permeability is high. Classic examples of such applications are deep water drilling, high pressure and high temperature (HPHT) regime and depleted reservoir environments. In the Niger Delta, HPHT reservoirs can be found in well depths up to 17000 ftss with a drilling window range of 0.4 to1.6ppg. Typical reservoir characteristics are formation permeability of 124 – 204mD and reservoir mobility of 112 – 1000mD/cp. Generally in this type of environment and essentially where there are high uncertainties in the reservoir pressures and formation characteristics, significant process safety incidents have been found to occur during pumps off events as a result of variations in BHP outside the allowable limits of pore pressure (lower limit) and fracture gradient (upper limit). The risks of exceeding the allowable limits are the possibility of taking significant influx volume if BHP falls below the pore pressure and loss of well bore integrity if the BHP exceeds the fracture pressure. Consequences of any of these events are high nonproductive time (NPT), well cost escalation and inability to achieve well objectives. This paper illustrates how in the recent HPHT exploration campaign carried out in Niger Delta, managing BHP was identified as a critical success factor. Hydrocarbon reserves of the exploratory objectives were successfully and safely unlocked by using MPD to maintain BHP within the allowable limits. The paper also illustrates how MPD application was enhanced by the use of high resolution pressure while drilling (PWD) technology.

The drilling industry has always relied on cement as a primary barrier. Although the cement represents about 5% of the well cost, when squeezes are required, cementing averages 17% of the well cost. Only 50% of the squeezes achieve the objective of establishing a barrier for well integrity. A little bit more than half of the failures can be attributed to operational challenges (pump failure, cement contamination), or design oversights (cement recipe, centralizers). However there are still cement failures with perfect design and field execution. These failures typically exhibit some of the following characteristics: high deviation, high pressure, washouts, natural fractures, long casing section, heterogeneous sands. For these specific conditions, it is beneficial to add an assurance that would maintain the integrity of the well even in case of bad cement. Some of the assurances used include port collars, external casing packers (ECP) and swell packers. Port collars allow a squeeze above the first stage cement, while ECP serves as a base for a second stage cement, and swell packers provides a baffle for sustained casing pressure. A more recent technology is the well annular barrier that can form a combined barrier with cement, and can also be used as a stand-alone primary barrier. The well annular barrier is a metal-expandable barrier that is expanded with hydraulic pressure. It is full bore, highly customizable, and qualified to ISO 14310. The metallurgy allows the packer to shape fit into either an open hole with irregular geometry or inside a casing to preclude annular pressure build up by giving a life-of-well reliable seal. The well annular barrier has been deployed in a variety of wells to achieve well integrity with and without cement, protect the B-annulus from sustained casing pressure, or serve as a barrier between reservoirs that cannot be commingled. This paper performs a review of the technologies used for cement assurance, their advantages and disadvantages. Case histories of well annular barrier deployments are presented, including a case where the well annular barrier was used as a stand-alone well barrier element without the need for dispensation. This paper also discusses how the well annular barrier fits into the regulatory requirements for well construction providing to the drilling industry an alternative to cement for the purpose of well integrity.

Objective A case story from ME will be presented covering an extreme extended reach, offshore well. Any increase to operating efficiency can save time and increase production. In this case story two SSD's were opened in a single run on e-line, an outstanding achievement due to the ID restrictions and extended reach of the well. The paper will discuss the planning, the operation, the achievements and the lessons learned. Methods, Procedures, Process This well was recently worked over, retrieval and new installation of upper and lower completion. Due to the well going on total losses during the workover, a closed system was deployed to enable the operator to set the hydraulic packers. The packer is utilized for isolation between two zones, with each zone having two SSD's in which one SSD per zone was required to be opened to allow access to the formation. From day one of planning the primary solution for this intervention was an electric over hydraulic toolstring made up of five tools, a 218 electric release device, 218 CCL for correlation, a 218 tractor for conveyance, a 218 stroker for the mechanical manipulation and a 218 key to address the shifting profile in the SSD (toolstring). A slimhole toolstring was required due to the packer ID of 2.81" The operator was using the service provider for other interventions on this workover campaign and decided to challenge them with opening two SSD's in one run while not shifting the adjacent SSD's. The challenging underlying economics of the industry today has created a powerful driver for operators to find more efficient, cost effective and safer intervention methodologies. The operation covered in this case provided just such improvements to the client: by utilizing electric line intervention tools the operator negated the requirement for a large footprint coiled tubing intervention. Results, Observations, Conclusions A System Integration Test (SIT) was completed onshore prior to mobilization, where multiple shifts were successfully executed on a 90° deviated pipe using a single set of shifting key pads. Test results were then repeated offshore, completing two interventions in a single run. The SSD's were successfully opened at ~12,000 ft MDRT and ~8,000 ft MDRT, respectively while leaving the two adjacent SSD's in the closed position. Results, client objective was 100% achieved using only electric line, enabling the client to move forward with similar well designs having the confidence that a safe, reliable electric line solution is locally available. Additional results include reduced HSE risks as the e-line approach eliminated the use of a heavier CTU. Further contributing to the HSE benefits on this operation, only 6 persons were needed on site and no heavy lifts were required. The paper will also cover some lessons learned as debris in the profile and tubing caused some challenges. Novel/Additive Information This operation shows how the industry is constantly trying to improve on existing methods in order to be more efficient, safe and cost effective.

This paper presents the development, qualification and field trial of a novel well flow valve that delivers unlimited zonal selectivity in single skin lower completion without the use of control lines. Control lines have limitations and risks due to complexity during deployment, restrictions on the number of zones, complications with liner hanger feed thru and associated wet connects. It is desirable to remove the control lines whilst maintaining the functionality of multi zone, variable choke flow control. The well flow valve is a full-bore, reliable and robust mechanically operated sleeve, qualified in accordance with ISO14998 including multiple open/close cycles, at a sustained unloading pressure of 1,500 psi, with highly customizable flow ports. The need for such a solution was identified by an operator in West Africa. The well objective was elevated from a gas producer to a well that required the flexibility to produce gas or oil with gas lift capability. The well flow valve was selected and required on site variable choke capability for both oil and gas production, with choke position verification, ability to handle dirty gas production without risk of plugging, compliant with a high rate and high pressure proppant frac along with ease of operation and long term reliability. The field trial included a high pressure proppant frac in the oil zone. In the shallower gas zone, three well flow valves were used to deliver variable choking capability from maximum gas flow rate with minimal delta P adjusting down to a choke size suitable for gas lift. The well flow valves were operated using a high expansion shifting key conveyed on eline through the 3 ½" production tubing. The shifting key expanded in the 4 ½" lower completion to open/close individually all the well flow valves in a single trip. Incorporating this new product overcame the challenges presented and met the objective of commingled production of oil and gas. The well flow control valve demonstrated flexibility through design, supply chain, manufacturing, and operations. This paper will also outline the future road map covering further developments of the well flow valve and its incorporation into an enhanced flexible lower liner solution aimed at lowering well completion costs and risks.

In the paper authors describe how seismic data disturbances affect scattering wave separation. They provide a set of recommendations for processing procedures that would improve the reliability of results. The original method based on mathematically precise solution of inverse scattering problem was performed to separate scattered waves from full multifold seismic data. Input data was modelled 2D seismograms and 3D field seismic data. Authors made observations on scattered wave separation result after adding different disturbances to modeled data and after different processing stages on real 3D data. Some conclusions and recommendations were made based on the observations. The paper shouldn't be considered as a deepest research of the problem. Only the main kinds of seismic data disturbances are examined.

"M" carbonate gas field in central Luconia province, offshore, Sarawak, Malaysia has been on production since 1995. The field is at the end of its life and all the gas producers scattered around the field are watered out having water cuts more than 95%. One of the main issues currently faced by reservoir management team is the prediction and handling of extremely high water breakthroughs at the existing producers. This paper outlines the basic and simple ways on how the team maximise the recovery from wells nearing end of life whilst minimising the cost of replacing water handling facilities at surface by adopting an approach of converting one of deepest gas producer well into Water Disposal Well (WDW), brought in the technique of well cycling and use of well rocking– method of unloading a well with other well. The field observed an early water breakthrough than expected and thus producing high amount of water. Since then the water imposes threats to gas production and water handling facilities. To cope with this issue various measures were taken. Team then proposes the efficient approach of well cycling, when gas rates decline, conversion of one of gas producer, deepest in formation, to be the WDW to facilitate the water production that is currently at 95% and then using the "well-rocking" for well unloading. The contribution from above techniques has proven an incremental reserves of 8% from existing wells with minimal additional cost. After the successful implementation and results of above programme, same has been applied to another nearby field which has proven the same results. The paper summarises the main issue of early water breakthrough and an effort to prolong the field production and results of converting gas producer to WDW, implications of cyclic production and their results, monitoring and example from two (2) fields.

Oil India Limited (OIL) is the 2nd largest national E&P Company of India. Its legacy dates back to more than 100 yrs. Change in economic environment of India has led to a faster rate of development and steep rise in energy need. To meet the growing energy demand, OIL too has grown: both in size and geographical spread to a pan India Company having global footprints in exploration and producing assets. Growing size and geographical spread, made it imperative for OIL to leverage advantages of emerging IT tools in its operations and processes. However, seamless integration of the IT tools with OIL’s golden legacy and culture is a challenge. Being an E&P company, monitoring of progress of drilling operations and production of Crude Oil & Natural Gas, their supply to consumers and analyzing their trend is of prime importance to management and decision makers. The prevailing method of paper based reporting and telephonic data flow in this legacy company ended to online tabular reports with the implementation of SAP ERP across the organization in OIL. However, the same was unable to fulfil the need and expectation of top management resulting in decision makers continued dependence on subordinates. The requirement of a modern day visual IT tool like interactive Dashboard with relevant online graphical data and analytics has become the need of the hour. This paper describes how an interactive Dashboard has been effectively and successfully introduced as an effective operational information and Knowledge Management tool in a legacy driven company like OIL. It also emphasizes special efforts made to customize the Dashboard in a way to blend it with existing methodology of information sharing to bring in acceptability to users. Further, the paper describes how successful and cost effective the in-house development/ implementation process compared to outsourced development.

Managing sand production is becoming an increasingly important issue for petroleum production wells, particularly in challenging environments such as deep water, or gas fields with high flow rate production where sand tolerance is very low and changing the completion strategy could be costly. Sand production prediction is an integral part of overall field development planning. Consequently, it is important that the risk of sanding is accurately evaluated and appropriate measures are taken for well completion. The critical part in a sanding study is to define a proper rock deformation threshold based on laboratory tests or field observations. Due to the lack of sufficient field sanding data or for the sake of modelling simplicity, the rock deformation threshold is frequently defined either inappropriately or too simplistically because of the failure to recognize the intrinsic heterogeneities of reservoir rocks.In this paper, two cases are presented with the deformation threshold "critical plastic strain limit" defined by a numerical simulation approach. One case represents a weak to medium-strength sandstone reservoir and the other a stronger, clean sandstone reservoir. In both cases, a comprehensive core testing dataset and a field-validated geomechanical model are available. In the weak-medium strength case, there were also several years of production history with sanding observations available from a few wells.The numerical method uses an elasto-plastic material model where the rock behaviour is numerically defined from systematic triaxial compressive core tests and a rock failure criterion based on the plastic strain limits modelled from Advanced Thick-Walled Cylinder (ATWC) core tests with calibration against field sanding observations. From the modelling of a range of high-quality ATWC tests and field sand production experiences, strong correlations are found between the critical strain limit and the rock compressive strength for both cases indicating different critical strain limit thresholds for different rock strengths and rock types.Although high-porosity and weaker rocks may still have a higher risk of sand production than low-porosity and stronger rocks, the risk of sanding may not be as high as predicted if a single threshold is used for the entire rock strength and porosity range. The use of a single threshold for the whole field could over- or under- estimate the risk of sand production, especially for reservoirs with a moderate risk of sand production.Sanding evaluations of the two cases revealed that the predicted sanding risk is potentially misleading if a simple sanding threshold is defined without adequately capturing the heterogeneity in reservoir rocks. This approach may prohibit the selection of an appropriate completion strategy for the entire field. This paper is concluded by presenting a rock testing program procedure for sanding evaluation studies to better capture the heterogeneity in reservoir rocks and, hence, to predict the sanding risk more reliably.

This paper discusses a case study of a 42-year-old mature offshore oilfield. For this field, with declining production trend and timeworn equipment and technology, understanding and analyzing the transient flow is not a well-defined process. The Integrated Operations (IO) project was kicked-off in 2012 in order to deploy an Asset Management Decision Support tool. One of the focus areas was ‘Flow Assurance Management’ to overcome challenges of well slugging, liquid surge management and to establish guidelines for Start-Up and Ramp-Up processes. Traditionally in this field, most decisions were based on steady-state well and network modelling without much emphasis on transient behavior. Moreover, lack of instrumentation and manual data processing and model updates made it difficult to estimate current reservoir/operating conditions accurately to support real-time decision making. To overcome these issues, a Dynamic Production Management System (DPMS) was designed and implemented based on a dynamic flow model describing multi-phase flow in the gas lifted wells of the field. This paper describes the system and how it aids in better understanding of flow performanxce issues, collaborative decision making, and improved communication between various operational locations and disciplines. As part of the IO project, Real-Time field measurements (pressure, temperature, flow etc.) were captured at high frequency (seconds) & validated to ensure the desired data quality. These measurements were automatically used as boundary information by the model which calculates pressure, temperature, flows and volumes in real time throughout the field. The model is used in different modes: (1) For real-time surveillance, the online model provides a series of virtual instruments at locations without actual instrumentation in the field. (2) For advance warning, a separate transient model is executed faster than real-time to predict future events for Slug/Surge Management. (3) Finally the model is also used for planning activities, such as Start-up/Ramp-up or pigging and can predict any alarming issues during these operations. Thus DPMS assists production engineers and operators to make proactive decisions for effectively managing flow assurance challenges and adds value in various areas. Surveillance: Continuous, real-time monitoring of operating conditions within the network, along with prediction of future conditions within the inlet separators.Safety (HSE): Prevention and mitigation of facility trips/shut-down due to slug and surge issues during start-up/ramp-upEfficiency: Improved utilization of engineers' time and experience with increased focus on data analysis instead of data manipulation.Production Gain: Proactive field management for improved production, rather than reactive decisions that lead to deferred production.Dynamic PMS: The system will help to fully optimize wells, networks and facilities in order to produce and operate asset to its fullest potential by minimizing unexpected downtimes It's one of the first fields in Asia to implement an integrated DPMS using the online transient model concept as a basis for effective, real-time and proactive decision support.

The world of mobile data acquisition is transitioning rapidly from paper and pencil to the smartphone and tablet. In this age of big data, one of the primary operational risks is how to collect reliable, accurate and timely data in a cost efficient manner. Modern operations require a large amount of accurate data to make informed engineering decisions on maintenance and operation of large numbers of assets, using OPEX as efficiently as possible. Remote locations, poor connectivity and a need for highly bespoke data acquisition tools mean that industry is required to solve its own challenges. Wood Group has been in the role of self-determination and innovation in mobile data acquisition for the better part of a decade and shares in this paper a series of key design decisions and case-study examples of the process in action. The experience shows that real efficiency gains are possible and that if industry can come together to solve some of the challenges in a connected way our work environments will continue to transform.

The initial well proving and early production period of a hydrocarbon field is a valuable and unique period of field surveillance where there is the opportunity to narrow the range of uncertainty for key reservoir properties through the use of inter-well interference testing. The Wheatstone gas field, currently being developed as part of the Wheatstone liquefied natural gas (LNG) project, is located offshore north-western Australia. The start-up of the Wheatstone field, due to the nature of constrained ramp-up for LNG supply and location of development wells provides a unique opportunity for early field life interference testing. This is due to periods of individual well and well combination flows that are ideal for pulse generation and detection, with many development wells observing potential pressure responses while nearby wells are flowing. This paper will focus on the potential of initial well proving flows for pulse testing at the Wheatstone field to capture reservoir information. Pulse testing can potentially be an important reservoir diagnostic tool, particularly during early production when the field is at initial state. Through considered test design strategy, detection of a pressure pulse in an observed well can be used to infer inter-well reservoir connectivity, connected pore volume and transmissibility. This paper provides a method to refine reservoir pore volume ranges and transmissibility. This will be accomplished through the use of dynamic model derived pulse testing type curves using homogeneous reservoir properties to match observed signals for selected active and observation well pairs within the Wheatstone field. A suite of dynamic models exist for the Wheatstone field. These models cover a wide range of possible realisations for reservoir outcomes that affect initial static volumes and dynamic responses including structure, reservoir net to gross ratio and petrophysics (porosity, permeability and saturation). Selected dynamic models that reflect the uncertainty in inter-well connectivity, driven by variations in net to gross ratio and petrophysics, were run to develop well proving profiles for selected development wells, with non-active wells observing for a pressure pulse from this activity. Following the reservoir simulation uncertainty study of well proving flows, a homogeneous reservoir property simulation model was developed based on the reference mid case dynamic model, with constant porosity and permeability applied to active reservoir cells in the mid model. A variety of type curve pulse responses were developed for a range of porosity and permeability ranges for well pairs. These homogeneous type curves are then used to match reservoir model responses for the well proving uncertainty study, leading to estimates of potential average pore volume and permeability between well pairs. Thus the use of homogeneous reservoir model matching of interference signals during initial field conditions can be employed to appraise inter-well reservoir property ranges.

As a result of the major investment in LNG (Liquefied Natural Gas) plants in Queensland, gas demand in Eastern Australia is expected to triple by 2017 when compared with 2014 demand (Office of the Chief Economist, 2015). This presents the opportunity to increase recovery from existing mature gas fields in Eastern Australia. While satellite and field nodal compression are common place for reducing field pressure and improving both production and reserves, the distance between centralised compression and some wells can be large, resulting in a pressure drop that limits the production potential from the well. Wellhead Compression (WHC), located at the well lease can be used to minimise this pressure drop, maintain high utilisation of existing compression infrastructure, and maximise reserves for a given well. This paper highlights how implementation of a WHC program with an accompanying management strategy has been applied to over 500 wells to deliver over 10 MMscf/d incremental rate and 70 Bcf of reserves with attractive economics and low capital expenditure when compared with new drills. WHC installations can add significant reserves and rate and are typically installed when a well is approaching abandonment rate. The WHC can remain on the well for the remaining life and, once production ceases, be moved to another well. This paper provides a case study for the successful application of WHC in a mature gas field, comprising a combination of conventional and tight gas reservoirs with over 600 producing wells and provides a methodology for determining: Well candidate selection & unit selection type The operator developed a methodology for WHC candidate selection based predominately on production data, reservoir properties, fluid properties and well completion type, with the primary objective being to lift wells above the Minimum Rate to Lift Liquids (MRTLL – Turner, Hubbard 1969) to enable stable production at lower pressures. This, in conjunction with parameters such as expected line pressure also enabled selection of unit type to ensure optimal economics. Unit type design & selection By working with one compressor packager and adopting proven concepts from North American production operations, the operator developed four standard unit types that can be applied to a vast majority of wells in the target basin. This resulted in significantly reduced engineering work, faster procurement without re-tendering and better operations integration. Multiples of the standard unit would be deployed where higher capacity was required. Overall fleet management strategy to optimise fleet performance The operator presents a unifying strategy, utilising expected well life for wells within the target basin to forecast the ultimate number of units that are required to achieve optimal rate, reserves and economics. Reserves growth Conventional analytical methods such as Rate Transient Analysis (RTA) and integrated production modelling are appropriate for estimating reserves growth as a result of WHC implementation. Additionally, a methodology is proposed to capture changes to developed and undeveloped reserves on the basis of WHC implementation, recognising that units will service multiple wells in various fields over their effective life. The operator has successfully applied WHC in a mature gas basin consisting of tight gas and conventional sands. The methodology presented can be applied to other fields, including unconventionals, to determine the applicability of WHC and develop an optimal field management strategy.

This paper highlights the phenomenal achievement of a Malaysian operator's first fast track drilling operation in a deepwater well offshore Borneo. The collaborative well planning (CWP) method fundamental to the drilling success is discussed. The discussed drilling environment is an overpressured deepwater area that has not only forced the earlier A1 and A2 to early total depth (TD) and caused abandonment of geological targets, but also contributes to numerous operational problems. Despite the challenges, operations on A3 ST-1 required significantly less operational time cost than budgeted. The difference between the previous two wells and A3 ST-1 was that, during the planning period, multidisciplinary concerns were addressed more carefully in real-time by employing CWP to unite geoscientists, drilling engineers, and other stakeholders using 3D integrated platform technology. This CWP helped the operator meet objectives for A3 ST-1, a fast track well that required only two months of drilling time, rather than the typical 12 to 18 months. It resulted in one primary well location and six geological sidetrack scenarios being accomplished in only one day. Upon the end of the operation, Well A3 was drilled with one successful cased hole sidetrack to geological target objectives without significant operational problems. A significant portion of the success can be attributed to the proper accommodation of concerns and best practices of rig usage, engineering insights, tool usage, and geological conditions during the planning process through the common software platform that can seamlessly allow collaboration of both geoscience and engineering data. The process automation only requires key drilling parameters to construct well trajectories, which was also significant in terms of shortening the planning time. This paper describes the first application of the CWP concept in offshore Borneo, which has become a trendsetter in terms of efficient and safe deepwater drilling planning and operations.

This paper will outline the events associated with Well-A integrity diagnostics, which took place prior to and during workover operations. Well-A tubing was pulled out and inspected by the workover rig. The results of workover operations assessment have distinctively validated previous rigless diagnostics. A detailed recap of Well-A sequence of events will be made in this paper. Well-A is a standalone injector. It has been especially completed to utilize the same well to supply and inject water simultaneously. Well-A has a 4 1/2" tubing completed on a 9 5/8" casing. The water producing formation is shallow and was perforated in the 9 5/8’’ casing. The produced water flows naturally to the surface through the tubing casing annulus. A surface pump injects the produced water into a deep formation through the 4 ½’’ tubing, as a reservoir pressure maintenance mean to support oil production. This unique downhole completion entails a set of challenges related to continuous well integrity monitoring and future corrective actions. A routine wireline temperature survey at shut-in conditions detected a downhole temperature anomaly. A heating effect was noticed compared to previous temperature surveys, which indicates upward crossflow from the injecting formation to the producing formation. The temperature profile started deviating from the normal geothermal gradient around the 4 1/2" by 9 5/8" packer depth. Two suspected sources of temperature anomaly were identified: a failure in the 4 1/2" by 9 5/8" packer and/or a leak in the tubing. Further well integrity diagnostic surveys were run to confirm the downhole temperature profile and detect the source of the temperature anomaly. Given the nature of Well-A's completion, a flowmeter log could not pinpoint the source of leak. As an alternative, a spectral noise log was run to distinguish the different flow characteristics of the well at shut-in, producing/injecting, and transient conditions. The transient logging technique was innovatively deployed in this special completion to record sounds from the leak source when the well was normalizing from injection temperature condition to shut-in temperature condition. The distinctive flow sounds of the transient logging mode singled-out the source of temperature anomaly to be tubing leaks. The accurate rigless diagnostics helped optimize the workover operations, saving rig time and allowing the proper planning of rig corrective actions ahead of schedule.

Drilling technologies are constantly being developed as operators push the envelope limits to maximize reservoir contact and increase hydrocarbon recovery. These advancements in well construction challenge the well intervention community to seek innovative solutions to successfully intervene in these wells. This paper discusses the successful combination of a slim OD measurement-while-drilling (MWD) tool run on coiled tubing (CT) for real-time survey of the open hole lateral wellbore, followed by a stimulation treatment at appropriate depths for all laterals in a single CT run. Saudi Arabia has been in the forefront of maximum reservoir contact well construction with the drilling of multilateral open hole gas wells; thus, the need for CT operations to enhance current offerings and procedures. For this application, several tests were performed to determine the feasibility of the combination of necessary tools to be able to steer, identify, and pump the stimulation treatment in a single run. MWD tools were run on CT in this multilateral gas well, and the stimulation treatment was performed during the same CT run. The common practice in the study area was to run in hole down to total depth (TD) and determine, only by depth difference, in which lateral the CT was located. The uncertainty level increased exponentially when TDs of the laterals were within hundreds of feet because the treatment could potentially be performed in an alternate lateral, rather than the one intended (Ref 1-5). With the use of MWD tools that can relay inclination, azimuth, orientation (steering capacity), pressure and gamma ray, all this uncertainty is eliminated to help ensure a positive lateral identification for proper treatment placement in the well. The MWD tool run on coiled tubing (CT), implemented a procedure explained in this paper to eliminate the uncertainty associated with previous technologies used for in real-time CT positioning inside the wellbore. The CT position is now reliable verified by survey match with real time readings from CT tip, allowing the certification of job placement in the desired wellbore path, to complete the intervention associated to the CT intervention; i.e.,: "a stimulation treatment" to be done specifically and independently for all laterals in a single run on each. This project open the doors for many other MWD-guided CT interventions to be applied in such conditions.

Sweet spot identification in unconventional fields generally involves the identification of clusters and intensities of parameters that indicate the resource volume and production-related parameters, i.e., reservoir quality parameters such as total organic content (TOC), porosity, permeability, pay zone thickness, etc. The process usually incorporates interpretation of seismic data, well logs and other data to develop a 3D model that is used to suggest locations for productive wells. While understanding these parameters is essential in unconventional resource development, the potential to achieve productive hydraulic fractures, or the potential to exploit natural fractures, or the potential to achieve both simultaneously determines the feasibility of developing an unconventional resource. There are geomechanical conditions that are favourable to achieve the maximum productivity from stimulation operations. Identifying the geomechanical sweet spots within the field-wide reservoir quality sweet spots is, therefore, essential for optimum placement of wells and hydraulic fractures in unconventional reservoirs. This identification requirement is gaining more and more attention in the industry, which is helping the technique and workflow development. This paper discusses the workflow to identify the existence and properties of geomechanical sweet spots including rock mechanical properties and natural fracture distribution and how they help to decide the vertical location and direction of horizontal wells for optimal reservoir development. The workflow requires a multidisciplinary data set comprising drilling, geology, geophysics, production, geochemistry and geomechanical information. Based on detailed geological understanding, either a 1D or a 3D geomechanical model is built as the foundation for further analysis. Images, seismic data and structural information are the key to develop the understanding of natural fracture distribution. A discrete fracture network (DFN) model, or other definitive models, is required to identify stress-sensitive fracture distributions under different stress conditions. Due to the fact that local in-situ stress and natural fracture properties can be altered by production operations, initial unsweet spots may turn into sweet spots at some stage of production or injection operations. Based on the results of comprehensive geomechanical sweet spot analysis, an optimal development decision can be made based on integrated geomechanics, production and net present value analyses within the identified sweet spots. This paper includes results and illustrations from several case studies completed for a number of fields in the Asia Pacific to demonstrate the concept.

This paper describes a two-year journey drilling deepwater exploration wells across three different countries, in challenging market conditions. The journey began in 2013 when the Transocean Deepwater Millennium was contracted by Woodside, in a 100 USD/bbl oil price environment, to drill deepwater exploration wells in Western Australia. The drilling campaign commenced in April 2014 with difficulties experienced through the first two wells. A recovery plan was initiated in late November 2014 that saw continuous improvement and top quartile performance achieved by the end of the campaign. These results were achieved despite the oil price falling below 35 USD/bbl and an unplanned transition to international waters in South Korea and Myanmar. This paper focuses on the practical steps taken by the Woodside (Operator) and Transocean (Drilling Contractor) leadership team to influence workforce culture and recover from a slow start. The recovery plan began with the alignment of Transocean's Management, Woodside's Management and the offshore leadership teams' vision and objectives. Technical Limit (TL) methodology was used to develop a set of performance indicators to monitor rig efficiency, establish clear and achievable targets for the off-shore crew, and to address the top five priorities for improvement.

Structural casing or conductor pipe provides a foundation for deepwater well and is designed to withstand the expected axial and bending loads. A very conservative design approach with worst case scenario is usually adopted for structural casing in exploration wells because the lack of information and high risk associated to deepwater operations cannot be underrated. This paper will present the evolution from a conservative to a fit-for-purpose engineering design approach. A design review with the latest interpretation of regional geological understanding derived from actual drilling experience was performed to quantify the associated uncertainties in the design phase. The result was compared with an independent analysis and validated during the actual installation performed by rig contractor. The project team supplemented this paper with a case study by sharing the conductor installation results from the jetting operation. In the early stage of deepwater exploration wells in Southeast Asia (SEA) region, many operators set their first string or structural /conductor pipe at around «80 m below mudline. This is a normal industry practice adopted from experiences in the GOM deepwater operation or operators' own experience in their deepwater field. This structural casing is generally jetted down with internal jetting BHA and drilled in riserless mode to the predetermined depth. This first string will not be cemented, and a subsequent surface casing will be installed and cemented to seabed. These two (2) strings will provide the foundation for a deepwater well to withstand the expected load, which are axial loads and bending loads. The conservative design generally uses a large size structural pipe like 36 in. OD with wall thickness from 1.5 in. to 2.0 in. WT. The second surface casing typically uses a large size pipe like 20 in. OD with moderate wall thickness. A weld-on connector are generally used for both structural and surface casings to accommodate the expected axial and bending load resulting from the installation of BOP and marine riser. The paper will describe the progression and transformation from the conservative to a fit-for-purpose design by optimizing the structural casing setting depth, its wall thickness and employing slim well architecture specifically for shallow well objectives below mudline. The most significant finding is that the slim design has proven to be suitable and was successfully installed in three (3) ultra- deepwater exploration wells in Brunei. This paper also will share the Company's experience and observation during the structural conductor installations to achieve efficient execution during jetting operations. The novelty of the fit-for-purpose design is in the ability to change the design norm resulting in substantial cost savings to the company and meeting the well objectives.

Well Intervention Plug and Abandon (P&A) operations play an important role at the end of life cycle of a subsea well in safely dismantling the well such that the well no longer poses any environmental hazards. P&A operations for subsea wells require sophisticated and efficient downhole tools that can operate at downhole pressures safely and reduce Non-Productive Time (NPT). A Dual String Section Milling (DSSM) downhole tool removes two adjacent casings in single trip reducing NPT while conducting safe P&A operations is discussed in this paper. This paper’s objectives are two fold first is to utilize advanced computational fluid dynamics (CFD) to improve DSSM tool life span for safe and economical P&A operations and second is to develop methodology for a quick and reliable solution for field personnel by combining CFD results with known closed form hydraulic models. The DSSM tool must maintain a certain pressure drop and flow range to achieve optimum performance. Higher flow rates and pressures can reduce tool life and cause erosion/washouts due to higher flow velocities. To address these issues simultaneously numerical simulations are conducted to optimize the DSSM tool design and operating parameters. To prove validity of numerical results CFD simulation outputs are compared against available test data and a good match is observed. Three dimensional CFD simulations are conducted using pressure based algorithm for numerically solving Reynolds-Averaged Navier-stokes (RANS) equation using second order upwind discretization scheme and k-ε turbulence model. Extensive CFD results are utilized in generating flow coefficients for closed form hydraulics models to formulate pressure drop versus flow rate charts for field usage. CFD simulations are conducted for flow rates between 100 gpm to 700 gpm to understand flow characteristics and pressure drop distribution within DSSM tool. CFD simulations showcased the locations prone to washouts; particularly washouts were observed around 90 degrees bend angles. The washout locations indicated by CFD analysis matched very well against the available test data. The DSSM tool design was then optimized using CFD simulations such that fluid velocities were below washout velocity and also higher annular velocities were maintained to alleviate hole cleaning problem during milling operations. The pressure drop versus flow rates curves obtained using flow coefficients showed correct trends with higher pressure drop for higher flow rates and higher pressure drop for reduced nozzle size. Thus utilizing CFD analysis, optimization and laboratory testing, service life of DSSM tool was increased, thus saving substantially on field NPT.

The Gorgon LNG Project is one of the world's largest natural gas projects and the biggest single resource development in Australia's history. Once online, gas from 18 subsea producers across the Gorgon and Jansz-Io fields will deliver a combined 15.6 MTPA of liquefied natural gas (LNG) to domestic and international export markets via three LNG trains situated on Western Australia's Barrow Island (Fig. 1).From May through to November of 2014 the eight Gorgon foundation wells were successfully perforated, intercepting between three and seven commingled zones and gross intervals of up to 500 metres (m) per well. Perforation was conducted on wire-line with a total of 69 perforating runs made during the campaign. Directly following perforation, all eight wells were unloaded and cleaned-up by flowing back each at 80 MMscf/d for 12 – 24 hours to the Ocean America mobile offshore drilling unit (MODU).This paper will contrast the detailed perforating and flowback plan, developed with numerous likely contingencies, against the actual results of the operation where a number of the planned and also some unplanned contingencies were enacted.The agreed perforating basis of design called for multiple wireline runs of 4.5" diameter guns with lengths of up to 80 feet, using a specially designed high strength gas blocked cable to accommodate well conditions. A top-down perforating strategy was planned to maximise the dynamic underbalance effect and optimise the clean-out of perforation tunnels. A number of operational events on the first well prompted a switch to a bottom-up perforating methodology that in turn had a number of significant knock-on effects which will be described in full.The flowback operation represented a once in a field-life opportunity to acquire commingled well samples and provide validation of several critical reservoir, fluid and well properties such as gas contaminant levels, water of condensation, compositional variation, vertical lift performance, sand production and the presence of formation water. As flowback operations progressed a feedback loop was incorporated, ensuring that the program was optimised as data gathered reduced uncertainty levels. Arguably the most commercially significant contribution, was the assurance that the deliverability of the eight Gorgon field producers was sufficient to meet their commitment to the Gorgon project.Ultimately, though sharing the susccessful case study of the Gorgon Perforating and Flowback campaign, this paper emphasises the value in developing appropriate contingencies in advance of operation commencement as well as retaining program flexibility to enable changes to be made at short notice throughout the operational campaign.

Notwithstanding the great technical changes that occurred in the offshore industry over the past decades, and the undeniable success of the subsea technologies, deepwater project sanction appears to remain rooted in traditional CAPEX minimization and NPV maximization. This paper investigates how decisions made by reservoir evaluation, and drilling and completion planning affect the design of subsea production systems and, in turn, the design of production hosts. Challenging the current approach to project framing and definition, practical alternatives are explored with a conceptual case study designed to test the ideas here presented. Deepwater production is expected to play a significant role in meeting the future oil and gas demand of the world. To do so, new fields need to be developed in challenging environmental conditions, and existing fields will undergo brownfield modifications to sustain acceptable production levels. OPEX will reflect the increasing costs for inspection, maintenance and repair. Rethinking the requirements of deepwater field development will help to define the proper size of the subsea and surface facilities, the optimal design life and the possible need for staged developments. A case study has been created to observe how changes in facility size, design life and development time-line (stages) result in changes to the overall subsea CAPEX and OPEX. These costs have been discussed with respect to drilling and completion costs and host facilities costs to identify possible opportunities and criticalities. Given the possibility of protracted low oil price environment, new ways of developing deepwater fields is worth considering. Greater integration of the various disciplines (subsurface, subsea, topsides, platforms, etc.) involved is also suggested in order to maximize the project objectives. Abundant scientific literature exists on deepwater field development, but limited information appears to be available on the optimal definition of project scope, facilities sizing and design life for a deepwater project that aims to be profitable and sustainable long term. This paper is a contribution to a wider discussion that the industry needs to have on the way deepwater projects are conceived, planned and executed.

The paper presents a new drilling technology. With the Electric Impulse Technology it is possible to drill boreholes with less energy demand, more drilling speed and less drill bit changes. Drilling results, calculations und further steps will be presented. The new technology uses high voltage impulses to destroy rock with almost no wearing of the drill bit. Engineering a drill bit with this technology will advance the drilling activity for oil and gas as well as geothermal drilling and mining. The objective is to develop a whole drilling system suitable for a conventional drilling rig. Within the first step an impulse voltage generator including a drill electrode was engineered, tested and evaluated. Drill performance under pressure with OBM was investigated. Next steps will include the developing of the energy supply for the system and field tests. The impulse voltage generator designed as a downhole tool was developed to drill bore holes with a diameter of 12 ¼ inch in hard rock with a drill speed of 1 to 2 m/h which is comparable to conventional drilling bits. Furthermore it withstands temperatures up to 200 °C and pressures of 1000 bar. The components of the generator have a lifetime about 350 h, so a bit could be used almost seven times longer than a conventional drilling bit. In laboratory tests a block of granite was drilled on a length of 50 cm with a diameter of 12 ¼ inch. Additionally further materials like limestone, sandstone, marble and iron ore were successfully destroyed. Pressure tests up to 500 bar with WBM and OBM were performed and analyzed. The whole design process of the generator and the electrodes was accompanied by network analysis and FEM calculation. The paper presents the new results of the development of a drill bit based on the Electric Impulse Technology. After the engineering of the impulse voltage generator and promising results the development of the power supply get into focus. The pressure tests show that the Electric Impulse Technology will work under borehole conditions. In addition to early processing the drill bit will be configured for drilling with WBM concerning environmental and financial issues.

This paper presents the Offshore Pipeline Engineering Competency Project. The project was initiated by the Australian Pipeline Gas Association (APGA) in 2013, in response to the resource shortage of skilled offshore pipeline engineers. This project has resulted in a national framework and standard for competency in the field of offshore pipeline engineering. The paper describes the Offshore Pipeline Engineering Competency Project from its inception through implementation with Engineers Australia for establishing a Special Area of Practice in Offshore Pipeline Engineering. The paper will describe the process used for competency development, the challenges and lessons learnt during the three year project; and the challenges that still lie ahead. The paper will detail the list of competency requirements and provide detail on the process of qualification through Engineers Australia. Finally, the paper will demonstrate how individuals and organisations can apply the competency framework for professional development. This project demonstrates leadership and innovation within the Australian oil and gas industry. The positive response within Australia and internationally, indicates the importance of and demand for, this work. Success is attributed to the high level of collaboration within the industry. The first industry benchmark in offshore pipeline engineering has been set. This has many positive outcomes including guiding professional development, guiding educational institutions and ensuring the future of the industry is secure by developing the skills of the engineering workforce. Establishing an Offshore Pipeline Engineering Competency framework is unique and the Australian industry is the first in the world to do this. There are ongoing discussions with international peak engineering bodies and standards organisations, to use this benchmark as the basis for a global framework. This will secure the future of the industry by ensuring that skilled resources are readily transferable between global regions.

Since LNG (Liquefied Natural Gas) is a combustible cryogenic liquid and as such presents specific safety hazards, the safety of LNG utilization has become an issue that requires a comprehensive study on the risks. Hence, various safety aspects connected with the operation of LNG need to be analyzed. The purpose of this paper is to review recent researchers' LNG safety studies and analysis. Specific safety characteristics of the equipment involved are incorporated in the analysis. The analysis of important risks show that at pressures near atmospheric, the hazards of LNG are comparable to those of conventional liquid fuels such as gasoline. At higher pressures, it behaves more like a combustible gas liquefied by compression. Also reviewed in this paper is the state of the art in modeling important LNG Hazards (like pool and vapor fires modeling). Totally, this paper identifies different possible risks in and out LNG plants and describes the results obtained from modeling of identified issues.

Existing operating facilities are often restricted by key bottle necks in the processing facilities that limit overall production. Typical bottlenecks limited capacities of separators and scrubbers that lead to liquid carry-over and in turn impact downstream compressors; water-in-oil emulsions leading to off-spec crude oil and too high oil-in-water content to meet discharge or re-injection specifications. By addressing and removing these bottle necks in a cost efficient matter the overall production and revenue of the crude oil production facility can be increased. Especially in the current environment, any investment costs should be balanced by a quick return on investment to make good business case for investment. In this work a general retrofit strategy is presented, that consists of several steps, including problem analysis, bottleneck finding, different solutions strategies, and a selection phase. The focus is mainly focused on how to optimize separators and get the most out of existing production facilities. A large focus of the production optimization methodology presented is on limiting the CAPEX requirement of proposed solution, in order to meet reduced budgets from oil operators in an industry suffering from declining crude oil prices. In order to achieve this different solution strategies are available and presented in this paper. Several case studies are presented in this paper, which clearly show benefits of the structured approach outlined. These cases shown how bottle necks are removed and overall production of a facility is increased.

Kuwait Oil Company (KOC) is developing Jurassic fields spread over 65 X 50 Km in North Kuwait, which are aimed to support the state's growing gas demands. The present contribution to Jurassic production is from Raudhatain, Sabriyah, NWRA, Um-Nigah & Dhabi fields of sour MM/NS reservoirs. Some of the wells and flowlines of these fields are located outside current KOC security fence very close to the existing public Farm Houses, posing great threat to public in the event of toxic H2S gas release. This paper mainly describes KOC's Production & Project Gas Group initiatives undertaken to mitigate the threat to public safety (potential Societal Risk) by implementing effective barriers to minimize the source and impact of any toxic gas release. Immediate safety measures undertaken include installation of field crash barriers along entire flowlines/corridors that prevent damage to existing surface flowlines. Mid-term protection by boundary fencing is in advance stage of installation for UN, NWRA, DA & Liyah fields and H2S warning signs are installed at well heads as well as along flowline routes. Long-term plans are underway to install required safety instrumented instrumentation for improved safeguarding systems of well heads, flow lines & the Early Production Facility (EPF-50) protection. The plan includes monitoring facilities of potential H2S release and public warning system (in two phases) for emergency preparedness and crisis management. The paper presents few specific cases of how by implementing the safety measures and barrier installations so far have yielded results in avoidance of hazardous condition and unsafe incident. In addition, the paper also presents process safety features like hazard analysis and risk assessment studies (HAZOP, SIL assessment, QRA etc.) carried out to identify potential risks associated with site specific situations (both for Jurassic field areas and EPF-50 plant) based on ALARP principle.

The paper presents the flow assurance challenges and the mitigation steps taken in the deep, high pressure & high temperature North Kuwait Jurassic (NKJ) Fields. Flow assurance is extremely diverse subject linked to different engineering disciplines. Understanding the reservoir fluid behavior, rock minerals, completion & pipeline metallurgy and operating envelope is critical to understand and overcome the flow assurance challenges. Pipeline Hydrate Formation is the biggest operational challenge, which frequently disrupts the production of some of the high producing gas wells during the winter months. Different chemicals and combinations of such have been attempted to mitigate the hydrate problem, still optimization of the chemical injection process is ongoing. Other problems of solid, scale or salt blockage in the tubing, surface chokes and pipelines have occurred and steps were taken to clear the obstructions. The NKJ fluids are highly corrosive and a corrosion inhibitor is injected at the wellhead to protect the surface pipelines. Addressing all these challenges require thorough knowledge of the specialized subjects and advance modeling to improve the field operational philosophy. In the NKJ fields, the pipeline connecting the well to the processing facility (5 – 30 Km long) are neither buried nor insulated. During the winter months (during night & early morning), the well fluid cools down below the hydrate formation temperature in the flowline causing hydrate crystallization and even plugging of the pipeline. Out of the 30 producing wells in the NKJ fields, half of the wells produce water and have hydrate tendency. The produced water salinity varies from well to well and range from fresh water to highly saline water with salinity as high as 330 kppm. This makes the system highly complex and manifest need for a robust solution. The paper walks through the traditional methods of hydrate mitigation done in the NKJ fields and the way in which transient model was initially built and continuously improved with more data. Currently methanol is used as the hydrate inhibitor and an anti-agglomerate (AA) is under trial. The methanol concentration is governed mostly by experience and on a reactive mode. An offline transient model advisor was built to understand the hydrate mechanism and optimize the methanol injection The advisor is still under trial, once simulation matches with the field conditions, then it will be online and linked to the existing KwIDF (Kuwait Integrated Digital Fields) technology program. Under KwIDF, Chemical Management workflow will be designed to optimize methanol injection to minimize the well downtime and reduce the OPEX cost. The transient advisor also can predict the surge at the facility inlet which can assist in balancing the production in and out of the facility.

This paper discusses the use of Solid Expandable Technology that allowed well deepening to reach Pre-Tula reservoir while maximising production liner size. The planning and execution of the first Kazakhstan installation and world record expandable open hole liner (OHL) application are examined. KPO b.v, operator of the Karachaganak field, planned to re-enter an old well, drilled in the former Soviet Union (FSU), abandon the existing openhole reservoir section, and sidetrack by kicking off directionally from cement plug, below the existing 7" production casing shoe. Due to the different pressure regimes (Permian - 1.03SG; Carboniferous reservoir - 0.83SG, and Tula bed formation 1.17SG) and the potential of taking losses and not reaching planned total depth of 5,267m with 5-7/8" hole, an expandable OHL was selected as a contingency option to isolate the high pressure Permian zone that transitions into a low pressure carboniferous zone with potential for loss of circulation. If needed, this would allow the Permian and Carboniferous to be isolated at top Tula, mud weight increased and reservoir drilled with 5" bit. This is larger than traditional well construction options maximising reservoir drainage. After drilling to top Tula, the 5-7/8" section was under-reamed to 7", drift run was conducted and the 5-1/2" × 1,403m liner was deployed to 5,167m with no open hole challenges encountered. The expandable OHL was expanded leaving a 5.2" internal diameter, after the cementing job. The system was drilled out and the reservoir section drilled with 5" bit to planned TD; the 3-1/2" × 4-1/2" tapered production liner was then set across the reservoir. This is believed to be the first installation in Kazakhstan and the longest 5-1/2" expandable OHL globally. The main objective of isolating the open hole section was achieved with no operational or safety incidents. The secondary objective of isolating a hydrocarbon bearing zone in the Carboniferous was achieved and verified by USIT that concluded that cement bond was of excellent quality across the section where future perforating may occur. This paper provides well construction teams information on an alternative solution that could be used in many other wells across the Eurasia region. Understanding the benefits achieved by KPO b. v. on the Karachaganak field may open up opportunities to extend field life where traditional technology has been uneconomical.