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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.

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.

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.

No matter where an asset sits in the plant, the need to understand its health on a real time basis has become increasingly vital mainly because of growing need to focus on HSE commitments, intense global marketplace and high energy costs, safer and greener work environment. While most facilities continuously monitor their critical machinery and asset, their less-critical assets - often called "essential assets" - cannot typically justify the expense of a traditional continuous monitoring system due to the installation costs of running wires and sensors. Today there is a growing proliferation of wireless devices for many industrial and commercial applications - for security, safety, surveillance and machinery condition monitoring. Wireless technology innovations promise to open up a wide range of plant floor applications where cabling is either difficult to install or prohibitively expensive.

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.

The quest for smart and cost-effective demulsification materials to separate water-in-crude oil (W/O) emulsions is highly desired in the petroleum industry. In this paper, an assessment study was conducted on the potency of coal fly ash (CFA) as a demulsifier for W/O emulsions. To our knowledge, this is the first study reporting CFA as a demulsifier for highly stable W/O emulsions. W/O emulsion samples were prepared without using any conventional emulsifier. Asphaltenes in the crude oil acted as an emulsifier and stable emulsions were produced. Six W/O emulsion samples of the same crude oil to water volume ratio (4:6) were formulated. A reference sample was selected for comparison during demulsificat ion. Demulsification tests were performed at room temperature (25 °C). Demulsification results obtained via the bottle tests showed that the reference sample (blank) without CFA remained stable without water separation after 48 hrs while the addition of various CFA quantities (1 % to 7 %) brought about separation of water from the oil phase. Separation of water was observed to have increased with increasing CFA addition in the emulsion. Water separation continued for each sample until around 24 hrs when equilibr ium was attained, and water separation remained constant. The W/O emulsion containing 7 % CFA displayed the highest performance with demulsifica tion efficiency (DE) of 96.67%. Demulsification comparison test results between CFA and a commercial demulsifier (poloxamer - 407) using same concentration and under room temperature showed that CFA was capable of separating water better than this commercia l demulsifier. This observation indicates that CFA can compete favorably with many commercia l demulsifiers available in the market. Additionally, the outcome of demulsification efficiency of 7% CFA at elevated temperatures (i.e., 60 °C and 80 °C) was around 98%. More importantly, the separated water at these elevated temperatures was clearer and contained lesser oil floccules than the separated water phase observed during demulsification tests conducted at room temperature (25 °C) condition. Shear rheology measurement reveals that CFA addition altered the viscoelastic characteristics at the crude oil/water interface at an aging time of 10 hrs and 55 mins. Viscous modulus remained stagnant while elastic modulus dropped significantly. Optical morphology revealed the phase transformation in the as-prepared W/O emulsion before and after the addition of CFA particles. The possible mechanism governing the demulsification of W/O emulsion driven by CFA particles was proposed. It is believed that this work will be relevant to petroleum exploration and refining operations.

The formation of emulsion is one of the challenges facing the oil and gas industry today. This is normally encountered when water is dispersed as fine droplets in the bulk of oil. This study presents the treatment techniques used by Nigeria Petroleum Development Company in Oredo field in breaking crude oil emulsion. Wells 2L and 4L were used for the analysis. Crude samples were obtained at the upstream of chemical injection points to ensure the samples were true representatives of the crude from the wells in the field. Chemical demulsifiers (DM1, DM3, DM4, and DM5) were formulated in the laboratory which was used in the treatment of 100ml of emulsion. Results show that DM3 and DM5 were the most effective chemical demulsifiers formulated in the laboratory for Oredo wells 2L and 4L respectively and also, temperature is an indispensable determining factor in the treatment of emulsion.

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.

Guided by the white paper, "Strategy for a Future Chemical Policy,1 in October 2003, the European Commission drafted a new regulatory framework for chemicals known as the Registration, Evaluation and Authorisation of Chemicals (REACH) policy. REACH is an integrated system that requires all substances produced or imported in quantities above one ton per year to be registered in the European Union (EU). The adoption of REACH will divert the burden of proof for putting safe chemicals on the market from the public authorities to industry. The formal REACH proposal is expected to be presented for legislation in December 2005. If adopted, an 11-year transition (phase in) period will be implemented in three stages, determined by production volume and chemical hazard. A new European Agency will act as the central point in the REACH system. This paper describes the proposed REACH system and its potential impact on an oilfield service company, both as an importer and downstream user of chemicals. The following topics will be discussed: Effects of REACH on producers/importersEffects of REACH on downstream usersImpact assessment of the REACH regulation on a service company as a case study

Abstract Stringent environmental regulations and higher costs of effluent treatments in oil and gas process industries have necessitated research into ways to improve the operating procedures in effluent treatment plant. In Gas-to-liquid (GTL) plant, a significant quantity of reaction water is produced and various chemicals are used as intermediate treatment chemicals. The reaction water is contaminated by these chemicals which impair the pH and the related properties of the water. The pH has to be controlled before the water is re-used or released to the environment. A laboratory-scale effluent neutralization unit for pH control was designed and built to demonstrate the feasibility of utilising produced carbon dioxide (CO2) from reforming reactions in both the synthesis and hydrogen production units in GTL plant for insitu effluent treatment. At the end of the reaction, the total volume of carbon dioxide used was recorded. This paper presents experimental neutralisation characteristics for different operating conditions. The prime advantage of this process can be thought to be less expensive than other published carbon capture and storage (CCS) processes. Moreover the carbon dioxide does not require further compression, dehydration and storage facilities before usage. Pipeline transportation is also drastically reduced since the captured carbon dioxide is utilised within the plant. This study demonstrated that, the neutralisation time increased by 3.15 minutes with increase in effluent volume from 40 to 60 litres and by 10.4 minutes as the temperature increased from 20oC to 50oC. The increase in the flow rate of carbon dioxide from 15 litres/min to 35 litres/min decreased the neutralization time from 19.15 minutes to 13.32 minutes. Finally it was estimated that about 64% of the daily carbon dioxide production which would have otherwise been emitted to the atmosphere was used in the treatment process. Introduction The fact that the concentrations of carbon dioxide in the atmosphere are increasing is known to environmentalists, researchers and government agencies. The causes of global change lie in the industrial activities of human society and ultimately in the population growth and increase in resource use by man. Human activities have increased carbon dioxide concentrations from approximately 280 to 355ppm since 1800 (Vitousek, 1994). This increase is likely to have climatic consequences on biota in all earth's terrestrial ecosystems. The need to reduce global climate change due to emission of carbon dioxide (CO2) and other greenhouse gases has led to research in carbon capture and sequestration (CCS). Several relatively small-scale carbon capture and sequestration approaches are currently in development and demonstration stages as highlighted by Hoekman, 2010. Direct injection into the oceans has also been suggested but there are a number of uncertainties over the ecological impact and equilibrium of the gas with the atmosphere. In the medium term, depleted oil and gas reserves, unmineable coal seams, and deep saline formations are the best options for carbon dioxide storage. Deep saline formations appear to offer the potential to store several hundreds of years' worth of carbon dioxide emissions. This must be validated, and site selection criteria must be developed and shared internationally to identify the most appropriate storage sites. Wider international collaboration and consensus are critically needed to ensure the viability, availability and permanence of carbon dioxide storage. However carbon capture and sequestration faces both technical and economic challenges. Therefore, there is the need to explore other methods to deal with carbon dioxide emissions. Transformation to chemical feedstock like methanol is a commercially proven technology, however carbon dioxide captured from flue gas from furnaces will not be economical for this purpose because of its low pressure. Recompression is required before the carbon dioxide could be processed to methanol (Ritter et al, 2007). Another well-known process - the Sabatier reaction, converts carbon dioxide to methane as shown in Eq. (1).

The SSP (Sevan Stabilized Platform) is basically a mono-hull with circular shape, depending on the same stability principles as a ship-shaped vessel. The SSP-300 refers to one SSP hull size, capable of storing 300,000 barrels of cargo. Differently than the SPARs, the SSP is wider than her vertical height, with an operational draft that is typically less than one third of her diameter. The circular shape dispenses the unit of any heading changes, since the seas face the same vessel hydrodynamical resistance, whichever direction they are coming from. Consequently, the SSP does not need turrets nor swivels, in order to handle the incoming oil flow, having the option of receiving the risers through a central moon-pool, while maintaining a spread-mooring system separately deployed from her outer hull. The design also includes important safety features, like double bottom and double sides, which allows for segregated ballast and offers structural strengthening. The highly symetrical shape is also conducive to modularity and a good stress distribution throughout the hull, preventing fatigue stress concentration and doing away with the need of using high grade steel. The result is that the hull is composed of a small number of different construction modules, used repeatedly, and a lower steel density for the hull, which translates readily into smaller construction cost and yard time. The SSP not only offers all the advantages of a regular ship-shaped vessel – like large storage capacity, big deck load, and spacious deck area – but has motion behaviour similar or better than a semi-submersible hull. Construction is facilitated by the intrinsic symmetry, which also offers access to all tanks from a central position, thus reducing piping and cabling. This paper will address these, and other features of the SSP (including the structural economies allowed by the design), describing a concept design that can be constructed virtually anywhere, and with enough robustness to compete sucessfully in a wide range of applications, throughout the world.

Selective plugging by microbial biomass is one of the proposed mechanisms for improving reservoir sweep efficiency in highly fractured reservoirs. In this study, the potential of Bacillus licheniformis strains isolated from oil contaminated soil from the Sultanate of Oman was tested for their ability to grow in induced fractures in carbonate rocks and to divert subsequent injection water to the unswept matrix zones. Three B. licheniformis strains were tested: B17, B29 and W16. Their ability to grow in minimal media with Omani date molasses as the sole carbon source was investigated. Two different concentrations of date molasses (3% & 8% w/v) were tested. It was found that the higher concentration of molasses gave higher growth rate for all strains. The combination of B. licheniformis strain W16 in a minimal medium containing 3% molasses was the optimum condition for maximum cell growth within 18 hours of incubation. Standard Indiana limestone core plugs were used for coreflooding experiments where a fracture was induced by slicing the cores vertically into two sections using a thin blade. The bacterial cells were injected into the cores and the ability of the microbes to grow and plug the fracture was examined. Coreflooding experiments showed promising results where enhancement of oil recovery was observed after bacterial injection. A total of 28.57% of the residual oil was produced after 18 hours of incubation. The results showed the high potential of using date molasses as the carbon source for microbial biomass production for selective plugging in fractured reservoirs.

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.

Enhanced oil recovery techniques are usually controlled by the cost associated with them as the fluctuation in the oil price, over the last years, is now commercially accepted. Microbial Enhanced Oil Recovery (MEOR) is one of the technologies that can potentially be implemented with an exceptionally low operating cost. Apart from economical interests of MEOR, microbial bio-products are found to be more environmentally friendly. Besides, some of the bio-products are more chemically stable in reservoir conditions of high temperature and salinity. In this study, biosurfactants produced by Bacillus licheniformis species isolated from oil contaminated soils from different parts of the Sultanate of Oman were investigated. Eight different production media using different sugars as carbon source such as: glucose, sucrose and cane molasses were tested on three of the potential strains to select the best medium that maximized the production of biosurfactants which was supported by the interfacial tension (IFT) reduction. All isolates were tested on their potential media to screen for the best biosurfactant producer among the available strains. It was found that the strain W19 gave the maximum IFT reduction (from 46.6 to 3.28 mN/m) in 16 hours of incubation when grown in medium 7. Further studies on W19 were done to test the interaction of biosurfactant produced by this strain with porous media in core flooding experiments as a tertiary recovery stage. The results showed high potential of using this bacterium during ex situ MEOR applications where 10% of residual oil was recovered after injecting the biosurfactant solution. Further recovery was observed after concentrating the same biosurfactant solution where additional 13% of residual oil was recovered.

Ivanhoe Energy's proprietary heavy oil to light oil (HTL) upgrading technology is designed to cost effectively process heavy oil in the field and provide a stable, significantly upgraded synthetic oil product along with by-product energy which can be used to generate steam or electricity. Analysis shows that HTL can virtually eliminate cost exposure to natural gas and diluent and capture the majority of the heavy to light price differential for oil producers. HTL accomplishes this at a much smaller scale and at reduced per barrel capital costs compared with established competing technologies. The HTL petroleum processing represents the application of a commercially proven technology to a new feedstock. Ensyn Group, Inc. initially developed the technology in the early 1980s and has applied it commercially for over 15 years in the biomass (wood) industry. Seven commercial Ensyn biomass processing facilities are in operation in the United States and Canada, with a major expansion recently completed in Canada. Ensyn initiated petroleum processing in 1997. A petroleum pilot plant built in 1998 has been used for testing crude oil from around the world. In December, 2004, Ensyn initiated operations at a 1,000-barrel-per-day commercial demonstration plant in the San Joaquin Valley in southern California. Ivanhoe and Ensyn merged on April 15, 2005, and Ivanhoe gained full ownership of the petroleum upgrading technology for the development of heavy oil reserves around the world. Ensyn Group spun off its existing biomass processing business, Ensyn Renewables Inc., to its shareholders prior to the closing of this transaction. Since the commissioning of its commercial demonstration facility (CDF) for upgrading heavy oil in early 2005, Ivanhoe Energy has tested a number of crude oils and vacuum tower bottoms feedstocks. Analysis of CDF performance shows that the HTL process is capable of delivering high yields of significantly upgraded product. The HTL process significantly reduces or eliminates most contaminants and the product typically meets pipeline specifications without further treatment. CDF run analysis validates data obtained in over 90 pilot scale experiments. Results of CDF runs, including plant performance data, CDF feedstock and synthetic product properties are presented.

With the goal to promote the search for continual improvement to the Industrial Safety function in an oil company with 42,000 employees, the Board of Directors of Petróleo Brasileiro S.A. - PETROBRAS established an evaluation process which considers assessment, every two years, of the Industrial Safety Management Systems of facilities. The process includes the rewarding of the operational unit that highlights the best Safety Management System. The article will describe the methodologies used in the evaluation process, which is based on the British Standard BS 8800 - Occupational Health and Safety Management Systems (1) and on the evaluation procedures of the National Criteria for Performance Excellence which emulates the American Malcolm Baldridge National Quality Award (2). The paper will also present the evaluation process methodology from the beginning: the first requirements, the development of the presentation report, the training scheme of the auditors and the field evaluation step, up to the definition of the facilities which got the most distinction in relation to Industrial Safety Management. The goals achieved by PETROBRAS with the establishment of this award will also be shown. This work started in 1995 and it is in its second evaluation edition and due to its results PETROBRAS was rewarded with the ALASEHT - Associação Latino Americana de Segurança e Higiene no Trabalho distinction.

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

Summary A revolutionary family of treating fluids designed for the stimulation of critical, hot, or exotic oil and gas wells has been developed through application of detailed chemical and engineering studies.1–3 Formulations based on the hydroxethylaminocarboxylic acid (HACA) family of chelating agents have now been used to successfully increase production of oil and gas from wells in a variety of different formations. Included in the field test matrixes were new and producing wells drilled into carbonates and sandstone formations. The temperatures of the wells treated ranged from 230 to 370°F (110 to 187°C) bottomhole static temperature (BHST). Because these formulations do not contain high concentrations of corrosive mineral or organic acids (the formulations are less acidic than carbonated beverages), very low corrosion rates of the tubulars can be achieved by application of small amounts of special, inexpensive corrosion inhibitors. The mild fluids also are highly retarded so that high-temperature carbonates can be stimulated and sensitive sandstone formations are not damaged. The fluids have reduced health, safety, and environmental (HSE) footprints because: They are much less toxic to mammals as well as to aquatic organisms than mineral acids or organic acids such as hydrochloric (HCl), hydrofluoric (HF), or formic acid. The fluids are returned to the surface at pH values between 5 and 7, and they frequently can be added to normal well production fluids without neutralization. Because of much lower corrosion rates for corrosion resistant alloys (CRAs), lowered concentrations of Ni and Cr will be in the well returns compared with conventional acids that also may contain antimony (as a corrosion inhibitor).

Upstream management and technological constant anxiety about production, transportation and storage or the crude oil includes gauging, running, and measuring processes variables (such temperature, API gravity, sediment and water, true boiling point, true vapor pressure) and consequently the evolves vapor rate in order not to removed it to the air as an atmospheric residual product but to be metered accurately to design properly the processes and operations to used it. Using tools such HySim, crude oil destilation and crude oil viscosity curve, it can be performed a complete oil characterization, defining composition, properties and of course the rate of the evolves gas during its storage in tanks.

Abstract Mesoscale test burns were conducted to determine the effect of water spray on the combustion characteristics of crude oil on a water surface. Data obtained during these burns suggest that the water spray increased the surface regression rate, decreased the smoke production, and did not reduce the fraction of oil consumed. Such information could be applied to in-situ burning of oil on water as an oil spill response technique. Introduction A test was conducted to determine if the injection of water into an oil-on-water combustion process would decrease the smoke production from the combustion reaction. Also of interest was the effect of water on the surface regression rate and the fraction of oil burned. Some qualitative evidence exists that water introduced into an oil combustion process reduces the production of soot particles, probably by altering the intermediate combustion reactions. In the design of smoke-free flares, water injection has been found to result in less smoke. Evans et al. found that the smoke yield from oil-on-water fires decreased by more than a factor of two during periods when the supporting water layer was boiling. It is possible that the water released during the boiling phase was responsible for the reduced smoke production. It was suggested that this theory be tested by injecting water, in a fine spray, near the burning oil surface. A small fraction of the injected water would evaporate in the reaction zone. The major portion of the water would reach the surface of the burning oil and evaporate during an explosive boiling process at the oil surface. A mesoscale test of the water injection concept was conducted at Mobile, Alabama, on May 22, 1991. This burn test was part of a series of 14 test burns conducted by the National Institute of Standards and Technology (NIST) at the Coast Guard Fire Training Center. Personnel associated with NIST were responsible for operations, data collection and analysis. Rick Shafer and W.G. Nelson, representing Alaska Clean Seas, were present and assisted during the test using water injection. Data from the Mobile tests used in this paper, unless otherwise specified, were obtained from the report presented by NIST personnel at the 1992 Arctic and Marine Oilspill Program Technical Seminar. REVIEW OF LITERATURE Available data concerning the combustion of oil on a water surface were obtained from relatively small test bums. A summary of these data follows. Regression Rate During Combustion of Oil on Water The regression rate of the oil surface during steady state combustion of crude oil on a water surface has been measured by numerous investigators. The consensus is that the regression rate depends most strongly upon the size of the burning surface and the wind speed. Wakamiya et al. found that for eight different crudes burned in a 2-m-diameter pan, the regression rates varied from 3 to 4.9 mm/min. There was no correlation between the specific gravity of the oils and the burn rates. For Alberta Sweet crude in a 1.2-m-diameter pan Evans, et al. measured regression rates from 2 to 2.4 mm/min for calm conditions. The regression rate was 2.9 mm/min for a wind speed of 1 m/s and 4 mm/min for a wind speed of 2.5 m/sec. P. 65^

An extra-heavy crude oil underground upgrading process is described which involves the downhole addition of a hydrogen donor additive (tetralin) under steam injection conditions. Using a batch laboratory reactor or a continuous bench scale plant (280-315°C and residence times between 24-64 h), physical simulation experiments showed an increase of at least 3° in API gravity of the treated Extra-Heavy Crude Oil, three-fold viscosity reduction and, approximately, 8% decrease in the asphaltene content with respect to the original crude. It was found that the presence of the natural formation (catalyst) and methane (natural gas) is necessary to enhance the properties of the upgraded crude oil. Compositional-thermal numerical simulations were carried out and the results showed a good match between the calculated and experimental °API gravities of the upgraded crude oil (average relative error 1-4%) for all conditions studied. Similar results were obtained with the asphaltene contents (14-23%), percentage of conversion of the >500°C fraction (12%) and tetralin (16-23%).

0. Abstract This Paper describes the quality assurance (QA) system developed and used by Statoil (the Norwegian stateowned oil company) in relation to the company's shipping activities. The objective of the QA system is to reduce the risk of accidents and to maintain a high level of performance by increasing the quality of the internal and external shipping activities. Introduction Statoil entered the shipping business as an operator of offshore loading tankers in 1979. Since then the activities have gradually expanded from 2 to 25 tankers by 1991, carrying crude oil, gas and refined products. Time charter parties for another 6 tankers, all new buildings, were signed last year with Norwegian ship owners. As of to day, Statoil is the world's largest offshore loading operator with a fleet of 9 tankers in operation. In addition, Statoil chartered approximately 800 tankers on a single voyage basis in 1990. Being an offshore company, Statoil is governed by an extensive quality assurance and control system QA/QC on all levels of the organization. This relates both to internal and external services. Thus it became natural to introduce a formalised QA/QC system to ensure a high level of safety and quality of the day to day operation of the tankers chartered by Statoil. 2. POLICY AND OBJECTIVES The governing policy of the QA-system is to ensure safe and reliable marine transportation including loading and unloading of crude oil, gas and refined products. This objective can in Statoil's opinion only be met by having a fleet of modern and well maintained tankers with a qualified sea and shore staff. Statoil's philosophy is that the cost of having such requirements pays its value by increased level of safety and performance of all operations. 3. STRUCTURE OF THE QA-SYSTEM 3.1 Time Chartered Vessels The QA-system imposed on the ship owners is in broad terms stating that all operations have to be conducted in an orderly and organized manner based upon specific requirements to the administration and standard of vessels and personnel. The ship owners must within two months after signing the charter party, meet Statoil's requirements by having an operational QA-system implemented. The QA-system should be based on ISO 9001/9002, IMO resolution A647(l6) or other similar and accepted standards. The individual ship owner should not only adopt existing standards, but also adapt them to his own organization. Statoil requires that the QA-system shall be formal, effective and used by all levels of the organization, but does not impose a predefined format of the ship owner's QA-documents. To ensure that the above requirements are met, periodical inspections and audits are carried out both at the owners premises and on board the tankers. premises and on board the tankers. 3.2 Spot Chartered Vessel Statoil's QA-system also includes all spot chartered tonnage in order to avoid sub standard tankers. Before the chartering department can conclude a contract, the tankers have to meet defined quality standards. The same applies to a certain degree for FOB tonnage. P. 839

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.

Abstract Field results from five commercial Microbial EOR projects with diverse reservoir conditions prove Microbial EOR increases production and reserves while decreasing water cut. The projects are located in different geographical areas of the petroleum industry with two in the USA, one in Argentina and two in China. Included is a dolomite and four sandstone reservoirs with average permeability ranging from 1.7 to 300 md. Microbial reduced oil viscosity and residual oil result in improved oil recovery. Production rate increases range from ten to five hundred percent, averaging thirty-nine percent. Oil recovery increases thus far average thirty-two percent. Numerical simulator results considering the two main microbial effects are consistent with field performance. On all five projects facultative anaerobic bacteria capable of deriving nourishment from the native reservoir environment are injected into the producing wells. The microbes are diluted with water and placed in the formation using annular batch treatments. Treatment size has ranged from ten to 450 barrels and frequency from every seven to twenty-eight days. Injection wells are treated as recycled produced water is injected. Microbe selection and effectiveness are determined and monitored by measuring changes in Newtonian behavior and viscosity of produced oil. Introduction Production data and laboratory results indicate microbes improved production and increased reserves on each of the five projects. Oil production rates are compared to baselines established by the operator before the start of Microbial EOR. Care was taken to continue field operations in the same manner under Microbial EOR as during the period the baseline was established. Laboratory testing for microbe induced oil viscosity decreases confirmed the effectiveness of the selected microbes both before and during the projects. Microbes can improve oil recovery byGeneration of gases that increase reservoir pressure and reduce oil viscosity,Generation of acids that dissolve rock improving absolute permeability,Reducing permeability in channels thereby improving displacement conformance,Altering wettability,Producing bio-surfactants that decrease surface and interfacial tensions, andReducing oil viscosity by degrading long-chain saturated hydrocarbons. For the reservoirs and microbes in these five projects, 4, 5 and 6 are considered the significant mechanisms for the reduction of residual oil and increased production. A typical reservoir was numerically simulated using three phase, black oil calculations. Considered in the simulator model are reduced oil viscosity, reduced residual oil and changes in relative permeability which occur as the microbes migrate or are transported through the reservoir. Model results are consistent with the field results. Projects The five projects listed in Table 1 represent a diverse geographic and geologic mixture. Two of the projects are in the USA, one is in Argentina and two are in the P. R. China. Lithology includes sandstone, fractured dolomite, siltstone/sandstone and fractured sandstone. Reservoir depths vary from 4450 to 6900 feet, net thickness from 18 to 60 feet, porosity from 0.079 to 0.232 and effective permeability from 1.7 to 300 md (Table 2). Reservoir temperatures range from 110 to 180 F and water salinities vary from 8,000 to 180,000 ppm chlorides, as shown on Table 3. All the projects are under waterflood. The five projects represent a wide range of reservoir and fluid properties as well as vastly different operating conditions and philosophies. These five commercial projects have increased oil production by thirty-nine percent or six hundred barrels per day: P. 633

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.

Abstract The product water on the P/6-A gas producing contains a residual amount of oil after primary separation treatment. This oil consists of finely dispersed aliphatic hydrocarbons with extremely small particle sizes and aromatic hydrocarbons dissolved in water. Due to the relatively high ratio of aromatics to aliphatics, the aliphatic hydrocarbon droplets tend to remain in suspension. This renders it difficult to separate out the dispersed hydrocarbons by means of gravity and coalescence. To comply with the prevailing regulation of 40 mg/liter of oil-in-water, secondary means of oil- in-water reduction have been explored. Several technologies have been tested such as a centrifuge, a hydrocyclone, membranes and a corrosion inhibitor. Observations a conclusions from the tests are presented. Introduction Mobil Producing Netherlands Inc. (MPNI) is a producer of natural gas and condensate on the producer of natural gas and condensate on the Netherlands continental shelf and is Operator of the P\6 gas field on behalf of the P\6 Groep B.V. The field, located about 60 km from shore on the Dutch Continental shelf (figure 1), is produced from the central P\6-A platform with five wells and the unmanned P\6-B satellite platform with three wells. The sales gas is evacuated platform with three wells. The sales gas is evacuated through the Mobil operated 89 km 20" pipeline to the L\10 platform and from then on through the 180 km 36" platform and from then on through the 180 km 36" Noord gas transport pipeline to Uithuizen for transfer to the N.V. Nederlandse Gasunie, the buyer of the gas. The P/6-A platform came on stream at the end of 1983, followed by the P/6-B platform two years later. The field is in decline and has currently a deliverability of about 2.4 million mn of gas. In 1987 the Minister of Economic Affairs issued a decree stating that effective January 1, 1988, the formation water discharged overboard from producing platforms, both oil and gas, may not producing platforms, both oil and gas, may not contain more oil (condensate) than 40 mg/liter. MPNI and other operators had difficulty in achieving the prescribed limit with installed equipment and started prescribed limit with installed equipment and started to investigate how to meet the requirement and what could be done to improve still further. Since that time MPNI has tested the following methods of reducing oil in the produced water: Centrifuge; - Hydrocyclone; - Membranes; Corrosion inhibitor. We like to share our results and conclusions of these tests bearing in mind what works and is suitable for one particular system or reservoir may not be so for another. THE P/6 FACILITIES The P/6-A platform has two processing trains consisting of separation, dehydration, compression and metering facilities. One train handles the well stream from the P/6-A wells and the other treats the fluid stream from P/6-B, which includes mono-ethylene-glycol (MEG) injected for hydrate prevention. prevention. In either train, after primary separation, the gas is cooled, compressed, dried with tri-ethylene-glycol (TEG), and metered. The sales gas is finally commingled with produced condensate for onward transportation to the Gasunie system. Daily water production at P/6-A is about 20 mn. As shown in figure 2 the water from the production separator, knock out vessel and the gas scrubbers is collected in the water treater. The water treater is a horizontal vessel containing coalescing pads and plats and operates at low pressure (1.7 pads and plats and operates at low pressure (1.7 bar). Its function is to separate finely dispersed condensate droplets from the water and to allow traces of dissolved gas in the produced water to flash out. The effluent discharged from the water treater is routed directly to a caisson with an outlet into the sea at 15 m blow sea level.

SPE Members Abstract The costs of replacing domestic oil and gas reserves are today dramatically different than during the "boom" years of the early 1980s. Changes in costs, tax laws, and drilling efficiency have altered the outlook for oil and gas and thus have fundamentally revised least-cost supply strategies. To provide a perspective on the new outlook, it is timely to re-examine the economics of finding and producing domestic oil and gas reserves. For this, producing domestic oil and gas reserves. For this, the paper reviews recent data on domestic oil and gas expenditures, reserve additions, drilling costs and supply sources. The paper also examines the response of drilling costs to changes in oil prices, rig utilization, and technology. The paper illustrates that least-cost reserve replacement will consider a supply portfolio that includes at least six sources:undiscovered conventional oil and gas,reserve growth from infill drilling,oil (and particularly gas) from the deepwater OCS,natural gas from low permeability sources (tight sands, coal seams and permeability sources (tight sands, coal seams and Devonian age shales),enhanced recovery of heavy and light oil, andexpanded development of the North Slope of Alaska. Specific case studies of coalbed methane development in the Warrior Basin, infill drilling in the Permian Basin, and heavy oil steamflooding in the San Joaquin Basin provide examples of how various companies are pursuing their individual strategies. Introduction During this period of low oil and gas prices, a persistent gas surplus, and major uncertainties about persistent gas surplus, and major uncertainties about future OPEC market strategy, the domestic oil and gas industry needs low-cost reserves. For firms to survive and prosper through this period of turbulences they need to continually pursue the answers to three key questions: What has been the past and may be the future costs of replacing oil and gas reserves? What developments are on the horizon that could alter the current conventional wisdom and outlook on oil and gas economics? What portfolio of supply sources leads to a "least cost" investment strategy? This paper provides background and analysis on five topics that address these key concerns, namely:Perspective on oil and gas reserve additionsReview of oil and gas revenues and expendituresDiscussion of the relationship of costs, prices and technology maturationAnalysis of reserves finding and development costsPresentation of a portfolio for future sources of oil and gas reserves PERSPECTIVE ON OIL AND GAS RESERVE ADDITIONS PERSPECTIVE ON OIL AND GAS RESERVE ADDITIONS After six impressive years that saw the U.S. maintain high rates of oil and gas production, replace its hydrocarbon reserves, and push the energy crisis onto the "back burner," concerns about domestic energy supply loom again on the horizon: P. 525

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. 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 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. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract An evaluation of stable water in oil emulsions (200 cp oil) at 180 degrees F as displacing agent is presented. The stability of emulsions as controlled by the pH of water. Displacement tests were carried out in consolidated Berea sandstone cores at a temperature of 180 degrees F. Secondary as well as tertiary recovery tests were conducted by injecting emulsion slugs followed by polymer solutions in order to control the mobility ratio. It was found that emulsions prepared with law pH water in a viscous oil were stable during the displacement process, and were able to recover up to 97 percent of the original oil at an approximate cost of 1 $ per barrel of extra oil with no need of a commercial emulsifier. Slugs of emulsion greater than 4 percent of the pore volume were able to maintain the displacement pore volume were able to maintain the displacement miscible during the whole process, recovering up to 7.5 barrels of extra oil per each barrel of oil in the emulsion when the mobility ratio was properly controlled. properly controlled Introduction Microemulsion flooding is a miscible oil recovery process which involves sequential injection of a process which involves sequential injection of a slug of microemulsion, a mobility buffer and water. The viscosity of the microemulsion and the buffer can be controlled in such a way that the mobility ratio is favorable during the displacement achieving high volumetric efficiency. The chemistry of microemulsions and their behavior in oil-water displacement tests are the most important aspects in the process. process. The use of microemulsions for secondary and tertiary recovery of oil have been presented in the literature. Laboratory as well as field tests have established their use as an important miscible method which is technically feasible. However the high cost of surfactant used in preparing microemulsions have limited its application in the field. Slug costs of 4 $/Bbl have been reported by Gogarty and Surkalo; they also indicated that in a large field test, the total cost of producing tertiary oil would be around 2.50 $/Bbl using micellar solutions. This work presents experimental tests showing that it is possible to prepare stable emulsions with some crude oils that can be used for secondary and tertiary recovery of oil without the requirement of commercial emulsifiers consequently reducing the cost of microemulsion slugs and thus improving the economics of the process. process.

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 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 OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract A new dehydration-desalting wash-tank design for treating large volumes of light crude oil is proposed. This wash tank has a perfect degassing system, a good coalescing area, and an ideal flow distribution. The effect of diurnal temperature changes is minimized and an undisturbed settling zone is assured. The design criteria of this new wash tank are explained. The various dehydration-desalting methods are reviewed and limitations discussed. Relatively light crude oil (above 30 degrees API) could be dehydrated with this new design wash tank to a sufficiently low final water content such that the desalting stage, using wash water, would not be required. This should result in considerable saving in capital investment, considerable saving in operating cost, and alleviation of problems in areas where the supply of wash water is scarce. Introduction With time, many oil fields will start producing formation water. The formation water can producing formation water. The formation water can be either fresh or salty. Salinities of 200 gm/liter NaCl are quite normal for many oil fields. The salt content of the crude oil depends on the salinity of the formation water and the amount of emulsified water. The generally accepted limit of salt in crudes shipped from the Middle East fields is 10 ptb (pounds per thousand barrels) at loading site. It should be mentioned that this crude, when received at European refineries, could have a salt content of up to 60 ptb due to contamination with sea water during transport (loading-on-top system, etc.). U.S. oil fields normally apply a limit to the water percentage, but not on the salt content. Any desalting is done at the refinery. If wet wells must remain on production, dehydration-desalting facilities have to be installed in the field. These facilities could be very costly. Dehydration (separation of formation water from the crude) and desalting (washing with relatively fresh water) can be done either chemically or electrically, depending on the quantity of the crudes the viscosity, the specific gravity, the temperature, the water content, and the cost of the demulsifier.

Abstract The Altamont area in Utah produces one of the highest wax content crudes anywhere in the world. These high pour point and hard to handle crude oils are an even tougher problem because of their location in a geographical area subject to very low ambient temperatures. Millions of dollars are spent each year heating these crudes in order to expedite their production and transportation. Crude oil samples from the area have been tested using a variety of techniques. Paraffin deposition, viscosity, cloud point, pour point, yield values, wax extraction and GLC tests have been conducted in order to characterize the crude oil samples. The effects of various chemical additives were then analyzed using the same tests. The effective paraffin inhibitors not only reduced the quantity of wax deposited, but dramatic shifts in molecular weight range and configuration were also apparent. GLC data indicates that effective chemical structures all reduced the quantity of C 40-50 molecular weight waxes contained in the resulting paraffin deposits. Introduction The precipitation of paraffin waxes from crude oil is a commonly observed phenomenon in the production of petroleum products. A variety of mechanical, production of petroleum products. A variety of mechanical, thermal and chemical treatments have evolved over the years to alleviate the problems associated with these deposition and pumping problems. If the wax content of the crude oil is low to moderate (0–10%) these problems are periodic and handled on an "as needed" basis. With wax contents above 10% these crudes experience severe deposition and flow problems necessitating constant treatment to ensure continued production. Many of these problem crudes display pour points above 30 degrees problem crudes display pour points above 30 degrees C (86 degrees F) such as Minas, Udang, Kuda Laut, Dickinson, Bombay High, Daqing and Handil. Particularly severe production problems due to high wax Particularly severe production problems due to high wax content crudes are encountered with the Wasatch crude produced in the Altamont, Utah area of the United States. Various methods have been designed to treat high wax content crudes including heating/cooling/ shear cycles, water emulsions, crystal modification chemical and heat. The use of chemical additives for pour point reduction and paraffin deposition inhibition is receiving considerable paraffin deposition inhibition is receiving considerable attention as new and improved formulations are developed. The combination of pour point, viscosity and yield value data has been determined to effectively describe a crude oil's rheological propertieswith and without chemical additives. Paraffin deposition testing using a variety of static cold spots, cold section loops, and dynamic probes has resulted in improved screening probes has resulted in improved screening techniques for paraffin inhibitors. The use of analytical instruments such as GLC, mass spec and GPC has led to information on the chemical composition and distribution of the high molecular weight fractions contained in the crude oil. All of the above techniques were used to study the Wasatch crude oil in order to identify active crystal modification chemicals for future field trial purposes. Wasatch Crude Oil Wasatch crude oil is produced in the Altamont area by flowing, beam pump, gas lift and power water methods. The wells are around 3050 m(10,000 ft.) deep with bottom hole temperatures of approximately 93 degrees C (200 degrees F). Severe paraffin deposition takes place in the upper 2000 m (6,560 ft.) and the flowlines and tanks are heated. While the crude is all classified as Wasatch it varies considerably in physical appearance. Three crude samples were tested which covered the range of properties observed in the field. Wax analysis, properties observed in the field. Wax analysis, pour point and cloud point were determined pour point and cloud point were determined by standard techniques. Table #1 is a summary of the physical properties. P. 321

Abstract The Cities Service-U.S. DOE Bodcau In-Situ Combustion Project in Bellevue Field, Bessier Parish, Louisiana, has been in progress since 1976. During this fireflood, oil, gas and water produced at 37 wells were analyzed five times to measure changes in the fluids resulting from the fireflood. One analysis was done during the dry burn phase of the project and four were done during the simultaneous water-air injection phase. Temperatures as high as 800 deg. C are reached in the dry burn phase and as high as 550 deg. C in the wet combustion phase. Burning of coke and oil at these high temperatures results in complicated chemical and physical changes of the fluids. Hydrothermolysis of the crude oil by the fireflood resulted in a lower sulfur content, a shift in the distillation curve toward increased amounts of lighter components and a slight increase in the API gravity and a decrease in viscosity. The methane concentration in the produced gas increased during the fireflood. Evidence indicates that this methane increase was produced by coke gasification reactions rather than thermal degradation of the crude oil. Introduction The Bellevue Field is located in Bessier Parish, Louisiana, east of Shreveport. The field was discovered in the 1920's, but due to the high oil viscosity, the wells produced at very slow rates. Pilot fireflooding began in the late 1960's. The Pilot fireflooding began in the late 1960's. The pilot firefloods were successful and the DOE project pilot firefloods were successful and the DOE project expansion began in 19761. Air injection in the five project patterns began in August-September 1976. project patterns began in August-September 1976. In March 1977, water injection into the upper part of the oil formation began. The produced fluids were analyzed five times from 1976–1979. One analysis was done during the dry-burn phase and four have been done during the wet phase and four have been done during the wet combustion phase. The oil analyses were done to determine any changes in the oil properties during the fireflooding project. Viscosity, boiling-point curves, gravity, project. Viscosity, boiling-point curves, gravity, percent sulfur, acid number and percent emulsified percent sulfur, acid number and percent emulsified water were measured. Viscosities were measured at three temperatures (37.8 deg. C, 48.9 deg. C and 60 deg. C) and at various shear rates on a Brookfield variable shear viscometer. In the May 1979 analyses, viscosity measurements were done on the oil-water emulsion and on the oil after removing emulsified water. The combustion gases were analyzed to monitor the progress of the fireflood. Percent oxygen, carbon progress of the fireflood. Percent oxygen, carbon dioxide, carbon monoxide nitrogen and hydrocarbons were measured by gas chromatography. Hydrogen sulfide analyses were done by the Tutweiler method and by the Cadium Sulfate Iodometric Procedure. In addition to these complete gas analyses, oxygen, carbon dioxide and carbon monoxide concentrations were measured twice monthly by field personnel using the Orsat procedure. The hydrocarbon and hydrogen sulfide concentrations were monitored to detect hydrothermolysis of oil or other chemical changes due to the fireflood. The sulfur content of the crude oil was reduced from the native oil concentration, showing that sulfur in oils was converted to hydrogen sulfide. Methane concentrations increased during the wet combustion phase of the fireflood. P. 277

The operation of bypassing the existing borehole by placing a kick off cement plug has historically been very well established and long-standing technique. Although placement of a cement plug appears to be a routine and relatively simple job, the instances of kick off plug not fulfilling the desired purpose are quite frequent requiring same degree of planning as primary cement jobs. Traditional cement slurry systems for sidetracking have been focused on the development of compressive strength by reduced water content. These cements exhibit low resistance to impact and toughness requiring multiple attempts to side track the well. An industry average for kick-off plugs is 2.4 attempts per kick-off, with 24 hours rig time associated with each attempt.This paper describes the engineered slurry system that incorporates unique properties of higher impact resistance, fracture toughness and load bearing capacity which resulted in slow ROP and sidetrack in 1stattempt. The main conclusion will be supported by case study at the end of paper.

Fiscal system is the basis for the estimation of take statistics ratio between Government and Contractor. This has been the case for the different versions of Nigeria's Royalty and Tax system and Production Sharing Contracts. Modifications in the currently proposed petroleum industry fiscal bill promise to ensure oil and gas availability, accessibility and affordability. Favorable upstream petroleum operations underlie the development and expansion of the midstream and downstream sectors. Fiscal incentives available to contractors make investment a worthwhile venture for both the government and contractor. The recently proposed petroleum industry fiscal bill (PIFB) 2017 is a favorable development because it is anticipated to reduce tax burden on investors, increase government take from royalty schemes and a dual tax system imposed on oil and gas projects. This paper applies a deterministic and stochastic cash flow model, analyzes the fiscal provisions of the existing royalty and tax system, production sharing contract and the proposed petroleum industry fiscal bill, 2017. Results from the model present a friendly royalty and tax deduction strategy in the proposed bill, which provides an incentive for investors to re-invest in the midstream and downstream sectors. However, the provision in the petroleum industry fiscal bill (PIFB) 2017 for royalty deduction during windfall is rather too fair at $50/bbl, considering a benchmark profitable oil price of $35/bbl during windfall. This paper suggests $35/bbl price for windfall threshold price for the additional $0.2 per dollar increase in oil price for royalty by value determination.

Deep offshore hydrocarbon resource development in Nigeria is of great economic interest due to security challenges limiting direct investment flow to onshore petroleum assets. However, Petroleum fiscal systems, which basically describe the relationship between host government and International oil companies (IOCs), are paramount in the deep offshore investment decision process. This paper focuses on assessing the implications on deep offshore asset development economics under the 1993 Production Sharing Contract (PSC) terms in comparison to the fiscal terms in the 2017 petroleum industry fiscal policy reform report. A metamodeling framework is proposed and applied in this paper. The framework adopted involves the development of deterministic cash flow models for both the 1993 PSC and the 2017 proposed fiscal terms. A range of profitability indicators for economic evaluation is generated and Monte Carlo simulation using @Risk software is applied to account for risks and uncertainties. The results reveal that the 2017 fiscal terms appear to be favorable to the contractor based on selected profitability indicators. In addition, there is strong evidence to suggest that the dual tax system proposed in the 2017 fiscal policy is economically attractive to the contractor when compared to the single tax system in the 1993 PSC. Hence, deep offshore E&P development is expected to be more rewarding to contractor under the 2017 draft fiscal policy terms than the 1993 PSC terms, ceteris paribus.

Maintaining a stable borehole is one of the major tasks during drilling operations. During the drilling, borehole breakout and drilling induced fractures are the two main instability problems which may lead to stuck pipe, sidetracking, and loss of circulation. To evaluate the stability of a wellbore, a constitutive model is required to estimate the stresses around the wellbore coupled with a failure criterion to predict the ultimate strength of reservoir rocks. The Mohr-Coulomb failure criterion is one of the commonly accepted criteria for rock strength estimation at a given state of stress. This failure criterion is mainly contributed from the cohesion and coefficient of internal friction parameters, which are determined by laboratory measurements. The laboratory measurements, although more reliable, are expensive and time-consuming. This paper discusses artificial intelligence models particularly multilayer perceptron (MLP) and support-vector regression (SVR) for predicting cohesion and coefficient of internal friction from elemental spectroscopy and petrophysical properties. Elemental spectroscopy, density, porosity, cohesion, and coefficient of internal friction data presented in this paper are based on various geological formations. Cohesion and coefficient of internal friction are determined through a rock mechanical test in the laboratory, while elemental spectroscopy data were obtained from X-ray fluorescence (XRF) analysis. We divide the data set into training and testing data. Training data is used to train MLP and SVR then establishes the cohesion prediction models. Similarly, training data is used to train and construct the MLP and SVR-based coefficient of internal friction models. Both models are then examined using the testing data. Cohesion and coefficient of internal friction predicted from MLP and SVR match well with the laboratory measurements. Two quantitative measures for estimation accuracy are used including coefficient of determination and mean absolute percentage error. Cross-correlation plots of predicted cohesion and coefficient of internal friction and the experimental results show very good coefficient of determination and relatively small error. The results demonstrate that amongst the MLP and SVR models, the models whose inputs are grain density, porosity, and elemental spectroscopy are the best models. From a practical point of view, the application of artificial intelligence techniques as a new method for indirect estimation of rock failure parameters are beneficial especially when the amount of core samples are relatively few.

Establishing a Big Data Analytics environment for Drilling operations is impacted by many factors such as the nature of drilling operations that requires quick decision making and has a diversity of data sources. This paper goes over the process of building a Real-Time Big Data Analytics environment and highlights key learning and challenges from this endeavor. The process of building such an environment is multifaceted. It involves building a Big Data solution architecture capable of handling the expected workload which includes servers, network, and software architecture. In addition, it requires establishing a data engineering pipeline that enables combining drilling data sets coming from different sources, reformatting and optimizing it to simplify and speed-up analytics. The data engineering pipeline is used to tackle different drilling data types which include a master structured database that describes the drilling planning, configurations, and operations, real-time drilling sensor data stored in WITSML semi-structured format (an E&P specific extension of XML), in addition to other unstructured content such as drilling reports. Data quality procedures were also added to the pipeline in order to identify and handle outliers in the data. In addition, data wrangling procedures were developed to ensure that the data is in the right shape and ready for analytics and machine learning. Moreover, this drilling analytics environment was built while maintaining all business security policies and fine-grained access control rules defined on the original data sources. The established Big Data Analytics environment results in a simpler and a shorter data science lifecycle and thus making it easy to combine, explore and deploy analytical models. This leads to more efficient business operations. Building a successful analytics environment requires much more than the technology piece. It involves many factors such as data ingestion, cleaning, wrangling while maintaining business security policies. This paper provide a unique perspective on how to build such an environment for real-time drilling operations.

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.

Production logging analysis in horizontal wells can be very challenging due to the fluid distribution and segregation. In addition to this, other factors such as the presence of heavier or viscous fluids, wells with debris or sticky materials add to the complexity of the downhole fluid profiling by causing uncertainty in estimation of phase holdups. This can cause significant errors in calculated flow rates or in some cases rendering most of the production logging sensors ineffective. In order to overcome these challenges, an integrated solution from different measurements is required to optimize downhole fluids profiling. In this paper, the application of Pulsed Neutron (PN) technology to provide a complementary measurement to enhance accuracy of the results is presented. PN technology can be used for independent PN phase holdup and water velocity measurements in near-horizontal wellbores with stratified multiphase flows. Comparison between phase holdups and velocities calculated from ArrayProduction Logging (APL) and PN devices are presented with field examples. Also discussed are the limitations and best practices pertaining to the use of these measurements. The paper details measurements that are not affected by the above mentioned issues. A well- calibrated PN measurement can provide phase holdups as well as water velocity, making it complementary to the APL measurements for characterizing production profiling under challenging conditions.

Polymer flooding is one of the most broadly implemented chemical EOR processes due to its low injection cost and its success in prolific production increments. This work develops an artificial-neural- network based expert system by utilizing numerically generated training data using a high-fidelity numerical simulation model. Injection-pattern-based reservoir models are structured to establish the knowledge-base that serves for the ANN training. The injection process starts with water injection and switches to polymer injection when the water cut reaches to a threshold value. The chase-water is followed after a prescribed amount of polymer slug is injected. The expert system is generalized in terms of reservoir rock and fluid properties, rheological properties of the polymer solution, and critical engineering parameters to adjust to the complexities exhibited in the polymer injection projects. In developing the inverse model for project screening and design purposes, we have used an engineering design protocol employing inverse and forward-looking expert systems with the goal of exploiting the non-unique nature of the inverse problems. In this work, we employ the expert system as a forecasting and screening tool that is capable to predict time series based response in terms of oil production, water production and injection well sandface pressure data. The validity of the forward-looking expert system is confirmed via extensive blind test applications within a 5.83% error margin. More importantly, we present a project screening protocol that couples the expert system and particle swarm optimization (PSO ) methodology to maximize the net present value (NPV ) of polymer injection projects. In this way, we take the advantages of the fast computational speed of the ANN model to evaluate the finesses of project parameters. In the application of the inverse expert system, we observe that the proposed design protocol is capable to establish a catalogue of polymer injection design parameters that satisfy an expected hydrocarbon recovery performance. The work described in this paper exhibits the robust nature of the proposed expert system in adapting to strong non-linearities encountered in the polymer flooding projects. The coupled utilization of the inverse and forward-looking modules, enables the design engineers to find solutions that are unique to the problem being studied by simultaneously satisfying the imposed constraints effectively. The expert system proposed in this paper is one of the modules of a comprehensive artificial-neural- network based toolbox that includes a large spectrum of EOR processes.

Multiphase flow measurements, based on tomographic imaging techniques, have made substantial progress in the past several years. In particular, ultrasonic tomographic reconstruction has shown its high potential in accurately measuring fluid fractions in a flow cross-section based on direct flow measurements. These types of measurements are very attractive as the system is nonradioactive, has direct contact to fluid, yet without flow obstruction. An ultrasonic tomographic multiphase flow meter (UTM) is being developed to capture the fluid flow rates and phase compositions in producing oil wells. The UTM aims to generate cross-sectional images of the flow inside the pipe. To recover these images, complex computations and high processing time are required, based on a limited amount of available data. For this purpose, compressive sensing (CS) reconstruction methods have shown great potential in overcoming the mentioned data quality and quantity issues. CS builds upon the fact that one can recover certain data of interest from potentially very few measurements. Many CS algorithms have been proposed in the literature. In this paper, we seek to find a suitable algorithm by comparing different CS algorithms in terms of the resulting recovered image quality. Specifically, we survey three algorithms in CS, namely basis pursuit, iterative soft thresholding (IST), and orthogonal matching pursuit (OMP). We also compare the results of the CS algorithms to that of a least-square based conventional algorithm. The numerical results show the superiority of CS recovery algorithms over the conventional approach, both qualitatively and quantitatively. The results also suggest that high image quality could potentially be achieved with less complex CS algorithms, i.e., the IST and OMP algorithms. As presented in the paper, our goal is to adapt CS reconstruction algorithms for images generated by the UTM, for the purpose of accurate quantification of oil, gas, and water phase fractions produced from different wells.

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.