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Eko is a prolific Deepwater brown field on production for 10+ years and cumulatively produced ~750MMSTB from 30+ producers and 25+ injectors (average cumulative production 25MMSTB/well). However, the actual ultimate recovery developed by producers vary from 90MMSTB which can be attributed to STOIIP distribution, reservoir complexity & development strategy. As the field has matured to production plateau and with sufficient static & dynamic data now available, a Deepwater Analogue study was kicked off to develop an Ultimate Recovery(UR) predictive model to benchmark the robustness of the simulation predictions for the next phase of in-fill development wells. This database will also support the quick evaluation of other Deepwater fields which are in advance stages of hydrocarbon maturation funnel. An integrated study was carried out to collate all static/dynamic data in each reservoir/well. Drainage area for each producer(s)-injector(s) well pair was defined (Figure 1) and associated average reservoir properties were estimated from latest history matched models. Several combinations of parameters were cross-plotted against the objective function (UR/Well) and a proxy function was established to predict UR for future wells. An error analysis was carried out on the reference case function to establish prediction uncertainty ranges. The simulation based P90/P50/P10 UR ranges for the future in-fill development wells were compared with this analogue database and where the forecasts from models were not in sync with actual observations in Eko field, modeling assumptions were revisited. As way forward, this analogue database will be updated with new well information, static re-modeling and/or history matching exercise. Also, the in-fill well results will be used as litmus test for the robustness of the analogue model. Figure-1 Amplitude Map Showing Definition of Drainage Areas for Major Reservoir (Red wells = Oil Producers, Blue wells =Water Injectors)

Deconvolution technique-which is based on nonlinear total least square (TLS) -is a mathematical tool that extracts the drawdown type curve from the rate and pressure history. This technique provides additional flow regime information that would not normally be seen within the specified time period of the buildup test through conventional analysis. It is an inverse process which aims to rebuild the theoretical reservoir pressure response during a single constant rate production period. This technique was adopted at different Tal Block wells in which conventional well test analysis didn't sight multiple no-flow boundaries due to small radius of investigation. A case is presented in this paper in which deconvolution was applied on a well, where reservoir pressure depletion effects were not matching during the test sequence with conventional analysis and the effect of negative superposition masked the boundary dominated flow, both of these issues were resolved using deconvolution technique. This technique have resulted in additional data/info of tested intervals which helped to resolve certain structural and reservoir uncertainties. However, application of this technique and yielded results should be considered/used keeping in view the assumptions involved in deconvolution, areas of its applicability and quality of data available. This paper presents principle, working, applications, limitations, and observations of deconvolution technique, available methods and a case study.

Produced water is any water that is present in a reservoir with the hydrocarbon resource and is produced to the surface with crude oil or natural gas. The major components of produced water are oil, grease, TDS, many organic and inorganic compounds. These components vary greatly from location to location and even over time in the same well. For Iraqi petroleum fields, the produced water in most cases is discarded into evaporation ponds outside the fields and this causes serious environmental problems for air, soil, and ground water. On the other hand, huge quantities of treated fresh water from rivers are used for injection in the petroleum wells to increase the productivity of petroleum fields from the oil in so called Enhanced Oil Recovery (EOR). A prediction study conducted by South Oil Company (SOC) indicated that the production rate of produced water in North Rumaila field varies (290000- 800000 BBL/day) from 2011 to 2028. For the above mentioned reasons, a joint research team from Petroleum Research and Development Center (PRDC) and SOC has formed to find solutions for produced water treatment to be suitable for reinjection purposes. In the beginning of 2010, a memorandum has been signed between Iraqi side (PRDC) and Japanese side (JCCP, WRPC, SWING) to start a joint project of PW treatment for reinjection application. Iraqi side collected the data related to the quantities and qualities of of PW in SOC, determined the required specifications for re- injected water and also selected the PW of South Rumaila field (Degassing Station NO.1) to be treated for reinjection. The joint research team (Iraqi & Japanese) hold several technical meetings to identify the PW problem and put the more suitable technology for treatment. The general philosophy of treatment was agreed by the the joint research team. SWING Company has adopted construction of a pilot plant (total capacity 10m3/day) to test the efficiency of the proposal treatment on ARTIFICIAL PW. Iraqi side provided the Japanese side with the types and concentrations of salts that required to prepare an ARTIFICIAL PW with similar properties of natural PW.Two Iraqi persons have been delegated to Japan for one month for training on installation and operation of pilot plant. After acquiring the skills of installation and operation by Iraqi operators, the pilot plant has been shipped to South Rumela field (Degassing Station NO.1) and installed by Iraqi operational team. The obtained results of the treated PW properties by the pilot plant were very good and met to the required specifications of water for reinjection.

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.

Sea water contains sulfate and formation water contains barium and strontium, if the sea water injected in oil fields reservoirs then the result is the potential for significant barium and strontium sulfate scaling and deposit & possible of reservoir souring due to SRB, s activity. Scale deposition is a common problem in sea water injection systems, the type and severity of scaling varying between fields. Sulfate scale formation is one of the most critical problems encountered in oil and gas industries daily activity and operations, the only effective way to avoid sulfate scale is to prevent it from forming. To prevent barium /strontium sulfate from forming and minimizing the potential of scale formation and associated well work over and squeeze treatment costs, Sulfate most therefore be selectively removed from sea water before being subjected to injection. A pilot plant CPP-NF (Compressed Phase Precipitation & Nano Filtration) testing was thus conducted to primarily and sufficiently deplete sulfate from sea water before being injected. The main objectives of the pilot plant is to study and evaluate the feasibility and cost-effective of CPP-NF technology for de-sulfation of sea water and/or MSF brine in Subiya Sea Water Treatment Plant SWTP, the foundation of the selected technology rests on how KOC can : 1) - increase the value and quality of the injected sea water, and 2)- implement the technology in such a way that the improved sea water quality would not cost more than the current situation and serve KOC long term goals. The pilot testing was very successful and the removal of sulfate was consistently in the range of 98–99%, furthermore, the pilot testing also revealed that the issue of high TSS (Total Suspended Solids) within the facility can be resolved at no additional cost.

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 In this paper the Gradient Theory of inhomogeneous fluids interface will be discussed and applied to compute the interfacial tension of hydrocarbon mixtures. The two inputs of the Gradient Theory model are the Helmholtz free energy densities of homogeneous bulk phases and the influence parameters of inhomogeneous interface. The bulk phase properties are calculated by the Peng-Robinson Equation of State. The pure component influence parameters are obtained from a correlation based on pure component experimental surface tension data, and the mixture influence parameters are determined from the geometric mixing rule. Experimental interfacial tension data for binary hydrocarbon mixtures and real petroleum fluids from two gas condensate reservoirs are collected and used to evaluate the Gradient Theory and Parachor Method. It is found that the accuracy of the Gradient Theory is superior to the Parachor Method which is traditionally used in the oil industry for interfacial tension predictions. 1 Introduction It is well known that the interfacial tension is regarded as one of important thermophysical parameters in many industrial processes. For example, in gas liquid separation process, there are strong dependencies between liquid interfacial tensions and gas-liquid separation performance, because both droplet size distribution and re-entrainment are sensitive to interfacial tension in the scrubber. In addition surface tension also plays important role in oil recovery process, extraction process, refinery process, etc. In spite of the importance of interfacial tension in petroleum industry, there is still a considerable lack of reliable experimental data in the open literature, especially near the critical conditions. Therefore, the theoretical and semi empirical prediction of interfacial tensions are of particular significance. There are several approaches which have been proposed for the estimation of interfacial tensions. These approaches can be divided into two categories: empirical correlations and statistical thermodynamics-based method which takes into account the density gradient between the bulk phase interfaces. The simple estimation method includes the Parachor Method [1-2], the Corresponding State Correlation [3] and the Perturbation Theory [4], which are not satisfactory for estimating interfacial tension of mixtures that exhibit strong hydrogen bonding. The statistical thermodynamics based methods include the Density Function Theory [5-6] and the Gradient Theory [7-8]. The Gradient Theory is of particular importance for practical computations of surface and interfacial tensions. It was originated by Rayleigh and Van der Waals [7] and rediscovered by Cahn and Hilliard in 1958 [8]. In this work the Gradient Theory of inhomogeneous fluid interface will be applied to obtain the interfacial tension of the hydrocarbon mixtures. The short descriptions of the Gradient Theory can be found in section 2. The Peng-Robinson Equation of State will be recalled in the section 3 and is utilized to compute some thermodynamic properties of the vapor/liquid phases and the interface. Finally the predicted interfacial tensions will be compared to experimental tensions. The superiority of the Gradient Theory is that it simultaneously can simulate mixture compound density profiles over the interfaces which are hardly accessible in experimental observation and measurement. The density profiles are very useful for theoretical studies and characterization of the interfacial behaviors of the hydrocarbon mixtures.

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.

The coal bed methane industry has been present in the United States since at least the 1920s. The most recent surge in activity began in the 1980s and was driven by tax credits. In the 1990s rising gas prices increased activity in both the United States and Canada. Activity peaked and is presently in a very mature stage in the mid-2000s as shale gas replaced coal bed methane. Coalbed methane and shale gas production has been present in the Cherokee basin since the 1920s (Figure 1). The reservoirs are generally found from 80 meters to 650 meters with an average depth of 375 meters. Many wells will flow gas in a very short period of time and generally have low water production. Individual reservoirs tend to 0.6 to 1.2 meters thick and are of Desmoinesian age. Reservoir characteristics have only been defined post field development. The Cherokee basin now has 20 years of production history for over 5,000 wells which allows a more detail analysis of reservoir characteristics and what actual reserves are.

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.

Drivers behind improving energy efficiency at any industrial site include environmental legislation, company policy, process optimization, cost reduction and not least the need to control the generation of Green House Gas (GHG) emissions. Energy efficiency assessments were carried out at a number of Total E&P UK Limited (TEPUK) sites, on and offshore. The assessment of each site followed a set format which include certain key steps; project kick off, full site survey and discussions, with operations and support staff. The assessments allow site specific action plans with short and long term improvements to be formulated and implemented. Analysis of cost, operability, maintainability, environmental impact, safety and security of supply has been used to justify and prioritize actions to be implemented. Recommendations for improvement differ greatly between sites, however there is a re-occurring recommendation to calculate and monitor energy performance indicators for each facility. Development of this indicator gives an operational baseline to measure process changes and improvements against. Close monitoring of changes against baseline provides additional feedback for process and cost optimization strategies. The value of energy efficiency assessments with regards to cost effective operation and process optimization should not be overlooked. Significant energy savings are achievable through detailed investigation – approximately 3-5% fuel savings are achievable through implementation of the "quick win" changes. Benefits are not only visible in process and associated costs. Environmentally, the reduction of energy consumption has a positive effect on GHG emissions and reduces the overall environmental impact of operations.

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.

Publication Rights Reserved This paper is to be presented at the 38th Annual Fall Meeting of the Society of Petroleum Engineers of AIME in New Orleans, La., on Oct. 6–9, 1963, and is considered the property of the Society of Petroleum Engineers. Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of JOURNAL OF PETROLEUM TECHNOLOGY or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in JOURNAL OF PETROLEUM TECHNOLOGY or SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted on request, providing proper credit is given that publication and the original presentation of the paper. 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 considered for publication in one of the two SPE magazines with the paper. Abstract Procedures which bring paper chromatography within the scope of the average oil field laboratory were found useful in obtaining and documenting information needed for the solution of such oil field problems as the selection of chemicals for the control of corrosion, prevention of oil-water emulsions, recovery of oil from sludges and prevention of scale deposits. Counterstaining methods permit identification of treating chemicals. Studies of their mobility in various solvents permit separation and identification of chemical entities and choice of those having more useful properties under field conditions. Introduction Paper chromatography is the art of using an absorbent piece of paper to study the behavior of chemical substances in various solvents. Small amounts of the substances to be tested are placed equidistant from each other at pencil points on a line parallel to and about an inch from an edge of a square or rectangular sheet of paper. Selected solvents are then caused to absorb through the paper's edge. As the solvent comes in contact with the paper's edge and passes beyond the points at which the substances are applied, a graphic picture is produced showing the effect of the solvent on the test substances. Since identical substances tend to behave in an identical manner, paper chromatography offers a useful method for demonstrating similarities or detecting significant differences in the chemical nature of the substances tested. It occurred to us that this is the kind of information needed to supplement the laboratory and field tests presently employed to evaluate the effectiveness of the various treating chemicals used in the petroleum industry. For instance, if chemicals which give outstanding performance in evaluation tests are used as controls, the similarity or dissimilarity in behavior of samples of other chemicals or different lots of the same chemical, when tested on the paper chromatogram, can be interpreted as evidence for or against the likeliness of their performing similarly. Attention might thus be fruitfully directed toward the evaluation of products which are significantly different in chemical properties. EQUIPMENT LIST 1 quart mason jar, wide mouth with lid Paper clips Spray bottles Support stand Whatman No. 1 chromatographic grade filter paper 0.2 ml pipettes calibrated in .001 ml 150 mm petri dish covers or 100 mm square disposable petri dish [Note: The plastic top off of a 3-lb coffee can will also serve as a dipping dish.]

This paper was prepared for the 43rd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., September 29-October 2, 1968. 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 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. "How to Write a Technical Paper", or "How to Write a Report" make good book titles. The subject is large enough to fill a book and many have been written. And there are several on the broader subject of clear writing. It is not the purpose of this paper to review the many ideas found in books of this type. Several are listed in the bibliography and the serious writing student can make good use of them. This paper is written assuming the reader has a knowledge of English grammar, its parts of speech, and the more important rules of putting those parts together in sentence and putting those parts together in sentence and paragraph form. From this premise them, this paragraph form. From this premise them, this paper will try to demonstrate how to make your paper will try to demonstrate how to make your product more effective. product more effective. WHY WRITE? First of all, let's differentiate reasons for writing from purpose of writing. Reasons for writing might include (1) a willingness to help out your buddy who is program chairman for the local section; (2) the boss wants a company report for the files on that engineering project you've just finished; (3) you want project you've just finished; (3) you want to try to get published in a trade journal; or (4) this is the only way you can get an all-expense-paid trip to the Fall Meeting. What-ever the reason, we have already decided that you (1) have something to say (2) that you know something that no one else knows and (3) that you can impart knowledge to others and make a genuine contribution to the literature in your particular field. The purpose. The only purpose in writing a technical paper is to get an idea across. May be it's to tell others what you have done and how you did it, or to describe a field operation or a unique equipment installation or possibly to summarize a field's producing life in a case history. A paper clouded with long sentences studded with an oversupply of many-syllabled words and dependent clauses just doesn't get off the ground. Scientific language, unless used wisely, compounds the confusion, and your paper becomes hard to read. Then readership paper becomes hard to read. Then readership dwindles and you have failed in your purpose. The audience. A major drilling breakthrough in the laboratory is worthless if it can't be explained to a driller. An idea that isn't understood dies from natural inertia against change.

There are quantum literatures, technical papers, etc on water management in the oil and gas industry. It is a very wide issue and with significant interest due to cost and environmental implications. The focus of this paper is water management in relation to oil production with the purpose of given the industry professional an all-round understanding of life cycle water management. Since by nature the oil is layered above water and the most common reservoirs drive mechanism is underlying aquifer (water), water production is therefore inherent in exploitation of oil. The impact of water in oil production could be good, bad or even ugly. This paper will discuss the various water management techniques from the drilling phase, through completion, production, transportation and treatment at processing facilities. Though basic, this is substantially fundamental. An improper management during any of the phases could prove very costly down the road to the promised developed ultimate recovery for a well completion and even overall recovery from the reservoir. With water production, comes the associated cost of water processing and disposal. It is the view in this paper, that practices and technology should be deployed to delay and minimise water production where appropriate. In today's lower oil prices for longer world, the industry must always strive to reduce their UOC (Unit Operating Costs) to remain profitable and competitive. There are published estimates of water handling costs being as high as 50 cents per barrel of water produced. Reduction in this cost will surely impact the operating company bottom-line. Though there are extensive literature that addresses specific challenges with water management in discrete phases of operation, this paper will attempt to provide a life cycle view, hence its uniqueness. It also highlights practical solutions that are tried and tested.