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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.

Introduction This paper deals with the use of Koh* determinations from pressure build-up curves as a controlling factor in primary field development. This method was recently utilized in the Ackerly (Dean Sand) Field, Dawson County, Texas. In this field conventional engineering calculations used to determine ultimate recovery, and thus profitable drilling locations, were not reliable. The Dean Sand reservoir in the Ackerly Field occurs at an approximate depth of 8530 feet, has a gross thickness of 250 feet and lithologically is an extremely dirty silt stone. Core data indicate an average porosity of 10 percent and a matrix permeability of 0.1 millidarcy. Core inspections indicate a minute vertical fracture system. The formation must be artificially stimulated to obtain commercial production.

A novel fibrous LCM coined "ARC Eco-Fiber" has been developed using deceased date tree wastes to use as an alternative to equivalent imported products. Every year about 5 to 10% trees are discarded due to old age, poor food bearing capacity and also due to the damage and degradation of trees by diseases. Currently, there is no industrial use of the discarded and deceased date palm trees available in the Kingdom. Moreover, the disposal of the deceased and old trees is a big headache for the date farming communities due to the economic cost and their negative impact on surrounding environment and the existing date farm plants. As there is a sustainable source of discarded and deceased date trees in the Kingdom, it is a potential source of raw material for localization of fibrous LCM product development to replace the equivalent imported products. The industrial use of deceased and old date trees will also boost the growth of local industries and enterprises along with the creation of new job opportunities for the local communities. It will also help to uplift the social and economic condition of the date farming communities. The date palm trunk-based fibrous LCM described in this paper indicates good ductile and malleable characteristics and thus expected to have good tensile and compressive load bearing capacity to prevent damage and degradation while pumping.The performance of the newly developed fibrous LCM "ARC Eco-Fiber" was evaluated using a see-through and a Permeability Plugging Test (PPT) Apparatus. The PPT apparatus used 2mm slotted disc, 250 oF temperature and 1000 psi pressure to conduct the tests. A commercial fibrous LCM product widely used by industry has also been tested to compare the performance of the date palm trunk-based fibrous LCM -ARC Eco-Fiber. The results demonstrated superior sealing and plugging efficiency for the ARC Eco-Fiber with little or no loss of whole mud compared to the widely used commercial fibrous LCM product. Both the conventional and see-through test results indicate effective sealing and plugging performance for the date palm waste-based fibrous LCMs and thus demonstrated the reliability of the product as an alternative to equivalent imported LCM products.

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.

Contamination of petroleum products at source has been a major setback in the downstream in Nigeria. Several mechanical crashes in the air, roads, and water ways have also been traced to cases of possible contaminated refined petroleum. There are no enabling laws to prevent these excesses. The aim of this study however, is to carry out a detailed simulated experimental procedure using different percentages of petroleum products from the Kaduna refinery as contaminants. The objective is to conduct several laboratory tests on the product sample for traces of mixtures with other products, in order to establish possible cases of unintentional contamination during handling at the refinery, to mix several products together and test for the possible traits from the mixture as well as the effect of such trait in the containing fuel and to determine the degree of contaminants in each of the mixture and to what extent it influences the individual characteristics of each product present in the mixture base on the degree of contamination. Materials used are PMS, AGO and DPK. They were contaminated with 85%, 90% and 95% of each product. Results show that for 85% DPK with 15% AGO had the highest SG at 15/4°C. This blend also had the highest distillation IBP at 175°C and EBP at 328°C with a flash point of 62°C, the cloud point, viscosity, colour and sulphur content were not recorded. For 95% DPK with 5% PMS had the highest SG at 15/4°C, distillation IBP at 95°C and EBP at 248°C, it has no flash point because PMS is very volatile, the cloud point, viscosity, colour and content were not recorded. The same procedure was applied for all the samples and compared with results from a few dispensing stations in Kaduna with some variation of impurities. It is recommended that handling of petroleum products and particularly the blending processes in our refineries should as a matter of fact be very thorough with proper re-examination of products using appropriate laboratory procedures before dispensing them to the public.

Gasoline is a highly flammable liquid derived mainly from crude oil that is used primarily as an energy source for internal combustion engines. To be competitive, gasoline must meet certain standards of high quality such as Octane number, Ried Vapor Pressure (RVP), and minimal environmental pollutions. This work aims at optimizing the production of a high-quality gasoline blend that meets the Octane number, RVP, Economic and Environmental standards, using varying oxygenates. The gasoline blending was executed by employing the linear programming solver application in Microsoft excel using four blending components namely the Fluid catalytic cracking gasoline (FCCG), Straight run naphtha (SRN), Straight run gasoline (SRG), Butane, and varying Oxygenates. The Blending process was simulated in ASPEN HYSYS simulation software, and the output product was tested for pollutant emissions in the same software. The selected blend was further optimized to minimize emission using the Response Surface Methodology in MINITAB version 18. Upon gasoline blending optimization and emissions testing, four blends met our specifications namely, the MTBE blend, the ETBE-blend, the Ethanol-blend, 1-Butanol blend. After a simple weighting method, the Ethanol was selected as the optimal blend having a net savings of 67.09 tons/year and 476tons/year of NOx and TVOC emissions respectively, a net increase of 16.35 tons/year of TTC emissions. The Blend was further optimized using RSM. The optimization results showed that SRG was the main contributor to NOx emissions, ethanol was a significant contributor to the TTC emissions while Butane had no effect of both emissions. The new optimized ethanol-blend gave a further 90.42% reduction in NOx emissions, and 67.85% reduction in TTC emissions, but with an increased amount of ethanol in the blend. The economics of a gasoline blending plant was evaluated, giving a pay-back period of 2.46 year, NPV @ 10th year of $177.6 million, an internal rate of return of 57.36%, and a profitability index of 3.04. This showed that the process would be highly profitable.

The impact of water, gas or a combination of both in oil production is an important aspect of petroleum engineering operations. Some water or gas production could contribute to oil production increase while in some cases such production could be less beneficial. Analytical techniques to quantify the impact are still lacking because the solution to multiphase flow problems in heterogeneous reservoirs is complex. Material balance procedures are deterministic and do not take into account the heterogeneity in reservoir behavior. Simulation techniques could be used but these are very expensive and require, a lot of time and information, which may not be handy. Using time series data analytics techniques, a method has been developed that is used to quantify the impact water, gas or a combination of both will have on oil production, in the short run and in the long run. This technique is also used to determine whether water, gas or a combination of both is a significant causal factor in oil recovery or not. The approach is innovative as it will help to isolate desirable and undesirable water or gas production before applying expensive diagnostics. This new Method has been tested with field data and could be a useful tool for reservoir and production engineers.

The oil mobilization in tertiary mode using chemicals has been shown to be a promising approach. In such technique, surfactants with or without polymers, designed for specific reservoir conditions, are added into water during water flooding to further drive remaining oil out of the porous structure of the reservoir rock into production wells. The success of the method depends on the cost of the chemicals used and the amount of the additional incremental oil mobilization achieved beyond water flooding. Thus, utilizing reservoir-compatible and inexpensive surfactants is a key. Petroleum sulfonates are some of the most abundant and inexpensive surfactants that can be made available at the scale required for efficient oil mobilization operations. However, petroleum sulfonates lack solubility in harsh reservoir conditions which makes them rather inapplicable for reservoirs with high salt content (e.g. > 50,000 ppm) and high temperature (e.g. 100 °C). We have successfully developed a simple, one-step nano-encapsulation technique to transform petroleum sulfonates into nano-sized multi-emulsion droplets in high salinity injection water featuring long-term stability at high temperatures. To further improve the economics and sustainability of such NanoSurfactants (NS), we developed a continuous and cost-effective synthesis process of petroleum sulfonates, directly from crude oil. The in-house-produced sulfonates were then formulated into a NS solution in high salinity injection water utilizing our encapsulation method. Results showed that petroleum sulfonates were successfully synthesized as seen from NMR analysis. The formulated NS was persistently stable at reservoir conditions, altered the wettability of the oil-wet rock as verified by contact angle measurements, and triggered crude oil release from the rock by spontaneous imbibition. This work provides a solution to produce petroleum sulfonates and formulate NS on-site for use in cost-efficient oil mobilization operations in high salinity and high temperature reservoirs.

Tetrakis(hydroxymethyl)phosphonium Sulfate (THPS), an environmental friendly biocide, is gaining more interest as a dissolver to control iron sulfide (FeS) precipitation in oilfield production systems. In previous works, combinations of THPS and different additives, such as ammonium chloride, chelating agents or organic phosphonates, were examined for the synergistic effects of FeS scale dissolution under room and high temperatures. It was found that THPS and ammonium ion can create a purple-colored complex which can significantly improve the FeS dissolution. Studies also indicated that the synergistic effect of ammonium chloride was largely attributed to pH decrease. As a result, the corrosivity of THPS solution to metallurgy was increased. In this work, new formulations based on THPS is introduced. Chloride ions were substituted with different organic compounds. The dissolution rate of analytical grade FeS solid and carbon steel corrosion were investigated at different temperatures. The chemical composition of the undissolved FeS solid and the THPS-Amine-Iron complex structure were analyzed for the most effective dissolver formulations. The efficiency of new formulations was further evaluated using field scale samples collected from water injection pipeline and a sour gas well, and the structures of the FeS scale before and after dissolver treatment were studied to reveal the mechanism of dissolution.

Abstract A novel method to remove nitrogen dioxide (NO2) from the flue gas of coal-fired power plants with CO2 capture has been advanced for commercial implementation. The technology leverages the equipment and chemistry in an existing (sulfur dioxide) SO2 polishing scrubber upstream of the main CO2 capture unit to remove the NO2, preventing degradation of the CO2 capture solvent and formation of nitrosamines. The report focuses on further evaluation of the chemical additives and operating conditions associated with the NO2 removal process to define conditions for commercial scale testing and deployment. Experimental work systematically evaluated a series of potential additives to minimize the oxidation of sulfite in a representative SO2 pre-scrubber solution. The additive combinations and concentrations were varied alongside important process conditions such as temperature, oxygen concentration, and metals present in solution to mimic the conditions expected in a commercial system. Important results of the parametric experimental work include identifying a new, potent sulfite oxidation inhibitor, revealing the importance of combining inhibitors with metal chelating agents, validation of a low-cost additive process, and development of a new semi-empirical model to represent mechanisms associated with sulfite oxidation. In addition, the experimental work revealed the impact of operating at higher temperatures (representative of a field test unit), which will guide the selection and concertation of additives as well. Techno-economic analysis identified potential net savings as large as $1.30/tonne CO2 captured and quantified the potential benefit of low cost additive options actively being pursued by the development team. Finally, the experimental results and engineering analysis supported the development of a detailed field testing plan and protocol to evaluate the technology at near-commercial scale. The field test preparation included development of procedures to introduce chemical additives to an existing SO2 polishing unit and identification of representative flue gas conditions based on a review of existing plants. These activities will have direct bearing on operation and design of commercial units.

Chemical consumption and wash water usage has risen in the past few years due to oil production having increasing water cut and emulsions. Saudi Aramco has installed and tested a new chemical injection spool that enhances the mixture of the injected chemicals and the incoming multiphase flow. The test consisted of two chemical injection spools: 24 in. and 30 in. units. The injection mixing spool has no moving parts and is installed upstream of the separator at the gas-oil separation plant (GOSP). The mixer incorporates specialized injection ports that channel the chemicals into grooves that ring the pipe and provide 360 degree injection. In addition, the internal geometry of the mixer generates turbulent eddies that enhance mixing. This static mixing spool has three injection ports: demulsifier, corrosion inhibitor, and scale inhibitor. The first system (24 in.) was installed and commissioned during the plant's maintenance in April 2013. The trial test of the chemical injection mixing spool spanned the summer months, which typically see a lower chemical consumption, as well as the winter months. Since being set on stream, the system has achieved a 48% reduction of demulsifier injection, which is a costly chemical. In addition, the wash water consumption was reduced by 31%, which supports the reduction of overall ground water consumption. These improvements were achieved while maintaining process integrity and desalting train efficiency. The second system (30 in.) was installed and commissioned similarly in May 2014. This unit achieved a 17% reduction in demulsifier dosage. Also, the reduction in wash water consumption was estimated at 12%. This paper describes the background to conventional chemical injection and mixing, specialized mixing spool design and working principles, implementation, and impact of the installation of the chemical injection mixing spool.

Excessive water production is one of the major factors in wells’ productivity reduction. It can be resulted from water coning and water channeling from water table to the wells through natural fractures, faults or high permeability zones. The use of foams or gels for controlling water production has been tested successfully in several field cases. However A large treatment volume is required to block the water influx that generally involves high operational and material costs. It is well know that injection of low salinity water into reservoir can mobilize reservoir fines and significantly decrease reservoir permeability. This paper presents the possibility of applying induced formation damage in order to block the water influx without hindering the oil production. This is a new cost-effective method using injection of low salinity water slug. It is shown that system of equations for water injection with induced fines migration and polymer injection is mathematically equivalent. Hence the polymer option in Eclipse-100 is applied to model low salinity water injection with induced fines migration. The modeling results showed that injection of 0.004 PVI of low salinity water above WOC resulted in significant reduction in produced water and improvement of oil recovery with no adverse effect on the oil production.

Abstract Case studies for potential Peak Oil curves, using Hubbert's models were prepared during the last decades for Brazilian oil production, at the time considering mature fields and the new pre-salt discoveries, however, since then, there has been mostly a lack of updated and new data and modeling to estimate a new peak curve for Brazilian production, which now take into account not only newer and better determined pre-salt reserves, but also new reserves in both the equatorial margin, the Potiguar basin, shale gas in the Paraná and Amazonas basins, and the more significant presence of natural gas in the Solimões basin, as well as the possible unconventional reserves. Also, a dimmer economic growth, new regulations in bidding rounds, and technical delays that have slowed expected production targets have all contributed to a new production forecast scenario, one that demands an updated set of Peak Oil curves for Brazil's basins as well as from a national perspective. Previous models estimated Brazil's Peak Oil curve point somewhere along the mid 2000 decade, however, this paper intends to demonstrate, through mathematical models based on Hubbert's model, that despite delays in new bidding rounds and production targets, that Brazil's new oil, and gas, peak curve has now dramatically shifted. Furthermore, this paper also takes a brief approach on the subject of Brazil's dependence on crude and gas imports and its relation with a new Peak Oil curve. And although it is likely that newer data from upcoming bidding rounds will shift such estimated curve, it is believed that a newer model, for illustration purposes, will indeed shear some light on where Brazil actually stands with self-sufficiency as well as a new growing global player in terms of reserves and production. Introduction This paper analyses and updates previous models for the productive lifecycle of oil reserves in Brazil through corrections and the proposal of a new model, closer to current and expected future production. As in previous models, previously available historical records were also considered as a source of data, as well as updated data on production and oil reserves in Brazil, as published by the Ministry of Mines and Energy (MME), National Petroleum Agency (ANP) and Petrobras. Aside from reusing and updating previous sources, in order to ensure greater fidelity to this new model, the following comparative sources were also added or considered: the latest Decennial Expansion Plan (PDE) from the Energy Research Company (EPE) and Petrobras' latest public Business Plan. Assumptions previously considered by past models as well as the implications of their mathematical modeling were reviewed and re-examined. Thus, when needed, new premises were developed, and a new model was created based on the theory of the "Hubbert Curve", elaborating various production curves for Brazil considering diverse possible scenarios. The development of this paper comes as a reaction to the absence of updated models that could more accurately and realistically show how uncertain it would be, according to the existing mathematical models and current reserve estimates, define a peak oil at this stage of Brazil's oil production lifecycle. Given the recent global changes that unconventional oil and gas sources have brought in terms of redefining the amount and location of world reserves, it then becomes necessary to establish and define new production peaks and self-sufficiency projections for countries, including Brazil.

For decades, it has been observed that temperature has a significant impact on viscosity reduction, mainly, in heavy and extra-heavy oils where increasing the temperature will improve the flow of oil through the reservoir. Austad and his group have reported that three main ions (SO42−, Mg2+, Ca2+) are potential determining ions for improving oil recovery in carbonate rocks. Both of them must act together. Their studies focused on studying light oils. At the same time, they pointed out the importance of injected fluid/crude oil/rock interactions. Water injection is the most widely used oil recovery technique which has been extensively applied globally in both light and heavy oil reservoirs for decades. Historically, the composition of injection water is dictated by the source of water available for injection. However, recent investigations have shown that the composition of the flood water can have a significant impact on oil recovery achived by water flood. Both total salinity and individual ions content of water have been shown to affect the performance of water flood. It has also been observed that interactions between water and crude oil may affect the oil viscosity. Most of the available research results are on light oil systems but the impact of water composition and its interactions with heavy oil have not been investigated. In this paper, we have experimentally investigated the interactions between brine and heavy oil. The focus of the study was largely on the impact of brine on heavy crude oil viscosity. Four different heavy oil samples were selected from a group of reservoirs and tested in this study. Experiments were conducted using different types of water at different temperatures. Synthetic seawater, formation water, normal brine and distilled water were used as selected brines. The heavy oils were brought in contact with selected brines such that each sample (system) consisted of 80/20 (brine/heavy oil) volume percent. The viscosity and water contact of the each oil was measured before and after the oil had been in contact with brine. The results of this paper indicate the crude oil viscosity may be altered due to contact with brine. The composition of brine as well as crude oil affect whether the oil viscosity increases, decreases or remains unchanged. The results are important for water injection and handling both on the surface and also in the reservoir.

The reduction in the total petroleum hydrocarbon (TPH) content of a polluted soil is not indicative of reduction in toxicity and soil recovery. However, it is expedient to design methods that will not only remediate the soil but restore it to support agricultural and biological activities. This study involved a bench-scale bioremediation experiment conducted to compare two treatment regimens, NPK and a combined NPK and cow dung (NPK + CD) to enhance petroleum hydrocarbon degradation and eco-restoration. The treatment was conducted in three microcosms representing each treatment and a control (unamended soil). Each pot contained 4kg of soil spiked with Escravos crude oil to a final concentration of 8695.77mg/kg and monitored for a 35 day period using gas chromatography-flame ionization detector. At the end of the monitoring period, 32.56% removal of TPH occurred in control while NPK treatment enhanced TPH removal with 64.62% and NPK+CD had a further biostimulatory effect on TPH with 67.56% attenuation, respectively. Phytotoxicity assay was conducted to determine the extent of soil recovery after the experimental monitoring period. Corn seeds (Zea mays) were planted in all experimental pots and a pristine soil (CTRL-UP) served as control. After the 8th day, root length, shoot length and plant height were measured as 23.3, 6, 10.2cm; 10.2, 5.5, 15.4cm and 4.8, 4.5, 14.2cm for CTRL-UP, NPK+CD and NPK, respectively and the corn plant in NPK treatment died before the 35th day. The results confirmed that bioremediation was nutrient-limited. The presence of requisite hydrocarbonoclastic bacterial community with optimal nutrient availability enhanced the rate of crude oil degradation. The combination of inorganic and organic nutrient amendment is a better treatment option as it improves soil structure, water holding capacity and generally possess a rich microbial population with hydrocarbon utilizing capabilities.

Produced waters containing high levels of oxidant demanding chemicals such as ammonia, hydrogen sulfide, and iron are often thought to be difficult to disinfect using oxidizing biocides such as hypochlorite. It is the goal of this paper to present evidence that chloramines generated in situ through the reaction of native ammonia present in produced water with hypochlorite added as a disinfectant can effectively control microbial populations in produced water. Testing was accomplished by treating produced waters being held in retention ponds with a hypochlorite-based disinfectant solution produced at the pond location using a mobile on-site generation (OSG) system. OSG in this treatment scenario involves the electrolysis of sodium chloride brines to yield a hypochlorite-based oxidizing biocide solution. This solution is then injected into the produced water at a rate to ensure that the Oxidation-Reduction Potential (ORP) of the treated water is ~450 mV. Samples of both the raw and treated water were analyzed for both chemical composition as well as microbial populations. Raw water in this study was found to consistently have relatively high ammonia content in the range of 58 to 120 mg/L along with an ORP in the range of −228 to 190 mV. Populations of Acid Producing Bacteria (APB) and Sulfate Reducing Bacteria (SRB) were found to be 1010 and 1011 MPN/mL, respectively. On site analysis of the treated water fond that the ORP after oxidant injection was between 464-543 mV, a value consistent with the presence of chloramines and not free chlorine. Populations of APBs and SRBs in the treated water were found to be 1 and 10 MPN/mL, respectively, representing a 10 log reduction in the resident bacteria population of these waters. Overall, this data clearly demonstrates that chloramines generated in situ through the treatment of high ammonia waters with OSG produced hypochlorite can effectively control the populations of key microbes in produced waters. Effectively controlling microbial populations using in situ generated chloramines offers the ability to achieve required disinfection of produced waters with hypochlorite based biocides without meeting the total chlorine demand of the water being treated.

Chemical flooding methods are used to recover residual oil left after water flooding. Several chemical flooding processes have been used to improve recovery. Alkaline-free surfactant polymer combination flooding (SP flooding) can avoid side-effects encountered in alkali-surfactant-polymer (ASP flooding) combination flooding. As part of the ongoing research on the use of Gum Arabic as a polymer in chemical flooding in Nigeria, this paper investigates the effect of heavy oil viscosity on oil recovery during SP flooding. Improved oil recovery through SP flooding was studied by conducting linear displacement experiments using engineering grade class IV glass beads. The glass beads were treated to be strongly water wet. The viscosity of oil samples used for the different experiments ranged from 3 to 140 cp. Lauryl Sulphate and Gum Arabic were used as the surfactant and polymer respectively. Result shows that oil recovery by water flooding ranges from 15% – 25% and for SP 15% – 35% keeping the polymer concentration constant. Thus, increasing oil recovery can be achieved as the viscosities of oil increases. The result from this study will help develop effective methods for implementing SP flooding using Gum Arabic that is vastly available in Nigeria in heavy oil fields. It will give the oil industry a new option for improving oil recovery from heavy oil reservoirs. SP flooding will be handy to improve oil recoveries from many marginal oil fields in Nigeria or those that face shut-down due to uneconomic operating cost, but still contain significant amount of oil.

Summary Thousands of well-perforation jobs are executed successfully around the world each month; however, certain perforation jobs require special design considerations to minimize the risk of equipment damage, such as bent tubing and unset packers, from perforating gunshock loads. Perforating guns generate pressure waves in the completion fluid and stress waves in structural components. The magnitude, duration, and timing of these waves depend on job parameters that can be adjusted by the design engineer, such as type, length, and loading of guns; number of shock absorbers; distance from sump packer to bottom of guns; and distance from completion packer to top of guns. The sensitivity of peak loads and gun-string movement to key design parameters can be evaluated with a software tool specifically developed to predict well-perforation-induced transient fluid-pressure waves and the ensuing structural loads. All relevant aspects of well-perforating events are modeled, including gun carrier filling after firing, wellbore pressure waves and associated fluid movement, wellbore pressurization and depressurization by reservoir pressure, and the dynamics of all relevant gun-string components, including shock absorbers, tubing, and guns. Existing fast-gauge pressure data from a large number of perforation jobs were used in previous jobs to verify that predictions made by using software simulation are sufficiently accurate, both in magnitude and time; thus, the transient pressure loading on well components is sufficiently accurate to predict the structural dynamics response and the associated gun-string loads. In this paper, we present case studies that show how key elements used for gunshock mitigation are simulated, and the sensitivity of peak loads and deformation to gun-string elements, such as shock absorbers, gun types and loading, tubing size and weight, and packer placement. With this software, we evaluate the dependence or sensitivity of peak loads and gun-string movement on/to key design parameters, and, when necessary, design changes are made to reduce potentially unsafe load conditions. The design verification and optimization methodology described in this paper significantly reduces the risk of nonproductive time and fishing operations. Key technologies described in this paper enabled the successful execution of many deepwater high-pressure (HP) perforation jobs, including Petrobras’ Cascade and Chinook, the largest deepwater HP perforation jobs performed to date in the Gulf of Mexico.

The production and transportation of heavy and extra-heavy crude oil are two of the paramount concerns in the oil industry due to the difficulties associated with heavy crude oil high viscosity. One of the most efficient techniques to improve the recovery and the transportability of such oil is to reduce its viscosity through dilution that can be applied solely or via thermal methods. In the present work, a new type of plant-based diluent is proposed, and its efficacy in heavy oil viscosity reduction for different concentrations, temperatures and shear rates is studied. Various concentrations of diluent, ranging from 5 to 25 wt%, are added to heavy-oil samples with different concentrations of asphaltene and viscosity, ranging from 48000 to 65000 cp in ambient temperature. A rotational viscometer was then employed to the measure viscosity of the prepared samples at the temperature range of 70 to 190°F and a shear rate of 3 to 50 s−1. The application of the proposed diluent led to promising results in that in caused the viscosity of the heavy oil samples to reduce by 93% in 75°F and 85% in 190°F with 20 wt% of diluent. To compare the performance of the proposed solvent and the common viscosity-reducing solvents, heavy oil samples were diluted with xylene and toluene with the same concentrations. Results indicated that the application of proposed diluent outperformed all of the commonly used solvents in terms of decreasing viscosity. The application of 20 wt% of the proposed diluent led to a 93% viscosity reduction of the heavy oil samples, which is 15% more than efficiency of adding the same concentration of toluene. The proposed diluent is a plant-based, non-hazardous substitute to the conventional hazardous diluents, e.g., xylene or toluene, that provides more efficient viscosity reduction compared to its conventional alternatives. Its flashpoint is higher than that of light crude resulting in less evaporation at high temperatures thus a longer period of reduced viscosity can be obtained. Furthermore, due to its high flashpoint, the proposed diluent can be employed in thermal methods more efficiently.

With the increasing awareness of global warming, geopolymer cement has been identified as one of the methods in reducing the emission of CO2 during oil well cementing operation. However, it is important that geopolymer cement can meet the specific requirement of oil well condition in order to be substitute of current conventional cement system. The use of fly ash in geopolymer based cement can affect the performance of the cement slurry by its properties which yet needs proper study to yield better advantages of it.In this research, the main objective is to study the effect of fly ash in geopolymer cement, by varying the properties which are thickening time, fluid loss and compressive strength. It is identified that the current conventional cement slurry is not environmentally-friendly, and is energy intensive. It is also identified that fly ash produced cannot be recycled and mostly being dumped. Thus, this study can provide the solutions to the problems identified. It involves extensive laboratory work in order to identify the properties of the cement.This project focused on the designation of fly ash based geopolymer cement compositions, the testing of the prepared fly ash based geopolymer with different compositions and different acid concentrations.This report comprises the literature review on the properties of geopolymers, the experimental works and their results, as well as the discussion and recommendations of the project.The tested parameters are water ratio, type and molarity of alkaline activator and alkaline activator ratio.The water ratio is 0.4 with the use of 12M of Sodium Hydroxide and the alkaline activator ratio is 0.4. Sodium silicate and silica fume was added to optimize the compressive strength which proved to have 31% increase of strength. Under low concentration acid, the cement is able to withstand the reaction but failed with higher concentration.The performance of the new blend will be analyzed.

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.

Nigeria is gradually advancing into the secondary stage of oil recovery, necessitating preparation for tertiary oil recovery especially enhanced oil recovery (EOR). Considering the high cost of EOR agents, it is imperative to investigate the performance of available local EOR agents against foreign agents when these agents (such as surfactants and polymers) are used in combination. Oil displacement experiments were thus conducted using foreign and local surfactant-polymer (SP) and alkaline-polymer (AP) agents on Nigerian crude and their results were compared. The experiments entailed using different percentage ratios of surfactants to polymers and alkaline to polymer. Four kinds of Alkaline were also used to displace residual oil from sand to find out what type of alkaline displaces oil better. The displacement efficiencies obtained from experimental results showed that the foreign EOR agents performed better than the local EOR agents. For the SP agents, the foreign SP displaced above 90% of both light and medium crude at about 45/55 percentage and 0/100 percentage respectively. The local SP displaced a maximum of about 35% of the light crude and 75% of medium crude at an SP ratio of about 20/80 for both cases. The use of Alkaline-Polymer results showed that the foreign agents performed better than the local agents. The maximum displacement efficiency of the foreign AP was 78.13% at a ratio of 40/60 while the maximum displacement efficiency of the local AP was 64% at a ratio of 60/40. The displacement of residual oil experiments performed using four kinds of alkaline showed that potassium hydroxide (KOH) enhances recovery better than NaOH, Na2CO3 and Palm bunch ash (a local source of alkaline). It was also observed that oil displacement efficiency increased as pH value of the alkaline increased.

Crude oil produced from the depths of the earth and during processing is associated with water or aqueous solutions of salts, particularly sodium chloride and during spills over waters, in the form of emulsions. Nigeria, an oil producing country, has remained dependent on foreign demulsifiers for the treatment of crude oil emulsion. This water interferes with refining operations, provoke corrosions, increase heat capacity and reduce the handling capacity of refining equipment and pipelines. Four samples of crude oil emulsion were collected from Ughelli East stations W/10L, W/10L, W/8L and W/1T, and labeled A, B, C, and D respectively. These samples were kept for few days at regulated temperature below their well head temperature to allow for natural gravitation. Meanwhile, four blends of local demulsifiers were formulated using locally sourced materials of non-edible jatropha curcas oil, industrial camphor, paraffin wax, starch from cassava and prepared liquid soap. These blends were used to treat the crude oil emulsion at a ratio of 1:50 ml using bottle test method at room temperature and regulated well head temperature in a water bath alongside the patent Separol N46 demulsifier as ‘control experiment’. The comparative results obtained showed that all local demulsifiers performance increased with separating time and operating temperature, while equal dosage of patent Separol N46 showed no performance. However, treatments AWHT4, BRT4, CWHT3 and DWHT4 all at well head temperature showed that most water was expelled after about 480 minutes. These results showed that the demulsifiers produced from these local content materials were cheaper, time effective and broke the selected crude oil within a shorter time frame than the foreign demulsifiers.

Foam has been used for controlling gas mobility during injection processes in order to mitigate the adverse effects of low gas viscosity, reservoir heterogeneity and gravity override. In addition, foam has also been employed in near-wellbore production, matrix acidizing stimulation, hydraulic fracturing, gas shut-off and water shut-off. The optimization of these operations requires a good understanding of the physical characteristics of foam and its behavior under reservoir conditions. Despite numerous experimental and theoretical studies on foam and some field applications reported in the literature, there is no comprehensive literature survey detailing the knowledge and experience gained through the application of foam. The aim of this paper is to present a critical review of the literature available on the use of foam injection for enhanced oil recovery. An extensive appraisal of the current status of foam application in EOR methods is a useful way of presenting advantages, shortcomings and limitations of the process as well as supplementary advances. Special attention has been given to the review of new research topics, such as the use of foam as a mobility control agent. Advances in more efficient foaming agents, additives and boosters are discussed. Moreover, in depth analysis of field applications of foam in EOR projects show that the main problems encountered during field-scale foam applications are related to foam stability, foam compatibility, as well as adsorption of the injected chemicals onto the rock surface. To address this, we discuss the evolution of the pilot field application and the reasons for inconsistency between laboratory results and field scale performance.

This paper provides substantial and compelling evidence from API (American Petroleum Institute) CCS (Carbon Capture & Storage) Work Group and other studies of CO2 EOR (enhanced oil recovery) and CCS projects showing that CO2 capture, transport, and (GS) geologic-sequestration can be a safe and effective method to reduce GHG (greenhouse gas) emissions and mitigate climate change. The paper summarizes how the oil and gas (O&G) industry has achieved great success in engineering the process to capture, transport, and inject CO2 in EOR projects. This success is seen in over 37 years of safe and environmentally friendly large-scale operations, lessons learned, technical advancements, and millions of tons of CO2 injected. Third party investigations to evaluate this successful record are discussed, including some completed ones that have published statements validating the O&G industry's success. Now that CCS is being widely considered and a few countries have begun to implement commercial-scale CCS projects, technology transfer efforts such as this paper are needed to share the experience of the oil and gas industry and the major contribution it can make as part of the solution for climate change.

This paper summarizes a critical review of possible microbially enhanced oil recovery (MEOR) methods and mechanisms to identify the most plausible utilization of microbial technology to enhance oil recovery. This paper is intended to stimulate discussion about broad applications of MEOR to field-wide improvement of oil displacement and recovery.The potential benefits of different MEOR mechanisms were examined for a representative North Sea reservoir of sandstone containing a light crude oil. In each case, the material input requirements for nutrients and inoculum were calculated in relation to the projected incremental oil production, assuming that the key components (bacteria, nutrients, or bacterial products) were uniformly distributed in the swept zone of the reservoir.The capillary number for the reservoir suggested that incremental oil recovery by biosurfactant production in situ would be modest under ideal conditions. The achievable yields would be lower because the Microbiol. in the reservoir would not be controllable to achieve sustained surfactant production. Losses of biosurfactants by adsorption to reservoir rocks and in situ biodegradation would further limit performance. The stimulation of surface active bacteria in the reservoir may affect the flow of fluids by producing emulsion droplets of oil coated with bacteria. The formation of a biofilm at the oil water interface changes the rheology of the interface, and may provide a useful mechanism to control mobility and areal sweep in reservoirs. Any mechanisms that required changes to large volumes of reservoir material, to produce gases, solvents, acids, or to significantly alter permeability, were not considered to be feasible. The limiting case of plugging fractures with bacteria and their polymeric byproducts does have considerable potential, but only for reservoirs which offer significant improvements in production with minimal injected volumes. The biological deposits must retain longer term resistance in situ to ensure that the anticipated production increase is achieved.This study provides a methodology for the systematic assessment of MEOR proposals using well-established reservoir engineering principles.

This report presents details of a proposed ship-based carbon dioxide capture and storage (CCS) method. CCS is one of the key technologies essential to achieve greenhouse gas reduction. This technology can also contribute to enhanced oil recovery (EOR) efforts by increasing oil production in mature fields. The liquefied CO2 (LCO2) to be sequestered is injected directly into subseabed geological formations through a flexible riser pipe using injection facilities contained onboard an LCO2 carrier ship. The primary characteristics of this LCO2 subseabed injection system are as follows: the presence of LCO2 injection equipment onboard the LCO2 carrier ship, a direct injection into subseabed geological formations through a flexible riser pipe, and the absence of any stationary sea surface structures at the offshore CO2 injection site. The advantage of ship-based transportation is flexibility in regard to i) multiple CO2 shipping locations and storage sites, ii) multiple injection sites from a large CO2 storage port, and iii) relocation of the injection site resulting from either termination of oil production or the site becoming filled with CO2. That is, ships can easily alter their shipping ports and routes to the offshore injection site(s), depending on requirements.

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.

Recent advances in guar and cross-linker technologies have resulted in the development of high viscosity cross-linked borate fracturing fluids without increasing polymer loadings. These Low Polymer borate fracturing fluids (LP) are successfully being utilized in various formations previously believed to be too hot and or too deep for low polymer fracturing fluids. Historically, polymer loadings of 3.6 – 4.2 kg/m3 (30-35 lb/1000gal) were commonly pumped in the Western Canadian Sedimentary Basin (WCSB) for formations deeper than 2500 meters and bottom hole temperatures greater than 80°C. These same formations are now fracture stimulated using the Low Polymer fluids with loadings as low as 1.8 kg/m3 (15 lb/1000gal) with exceptional results. This paper demonstrates that Low Polymer fracture fluids can be used in place of higher polymer fluids with minimal changes to the overall design of the fracture treatment. The new fluid can be pumped on-the-fly at conventional pump rates and proppant concentrations due to the fluid's improved shear and temperature stability. The advantages of using a reduced polymer fracturing fluid include increased production, lower treatment costs, and lower friction pressures. This paper illustrates these advantages as it compares the Low Polymer fracture fluid with High Polymer fracture fluids in over 200 wells in the WCSB. The formations where LP fluids were utilized have depths of up to 3250 meters and reservoir temperatures reaching over 100°C.

Summary High Precision Monitoring of Crude Oil Tanks is very precise and accurate dynamic measurement detecting any Leak during operations. For many decades, the oil industry has been concerned with the financial consequences of oil losses. In recent years, there has also been an increased awareness of the industry's environmental impact. Pollution, caused both by liquid spills and atmospheric emissions, is an area of increased concern, and the industry has initiated programs to reduce the risks of environmental damage. Maintaining an accurate leak detection and reconciliation program is a necessity for anyone environmentally conscious such as a tank farm owner. This paper describes the innovative solution developed by ZADCO maintenance team for High Precision Monitoring of Crude Oil Tanks system. It also describes the existing Crude Oil storage system hydraulics, technology of level storage tank measurements and control system utilized in developing the High Precision Monitoring logic algorithm. It shows relatively preciseness if the developed solution and the control on the different operations modes and scenarios. The solution became an online dynamic diagnostic and alerts the operators if unpleasant or abnormal operations accur in a time span of 27 seconds.

Water-based drilling fluids consisting of xanthan gum, starch, sized calcium carbonate and salt particles have been used to drill horizontal wells. Available chemical methods of removing filter cake like mineral acids, esters, oxidizers, and chelating agents are limited at certain conditions. Drilling fluid was designed based on calcium carbonate particles and an ester of lactic acid. The objective of the latter is to remove calcium carbonate once the drilling operation is complete and there is a need to remove the filter cake. Extensive lab work was done to: 1) determine thermal stability of the drilling fluid (70-72 pcf) for 24 hrs, 2) characterize the filter cake using computer tomography, 3) assess potential formation damage for different rock types (limestone and sandstone) using a modified HPHT filter press, and 4) determine the removal efficiency of the filter cake and the return permeability. The results obtained showed that the drill-in fluid has stable rheological properties up to 250°F over 24 hrs. A CT scan showed that the filter cake contained two layers, one layer close to the rock surface, which contained a mixture of calcium carbonate and acid-precursor, and one layer close to the drilling fluid that contained a mixture of XC-polymer and starch. The polymer layer was removed by using 10% solution of alpha amylase. The rest of the filter cake was removed by lactic acid that was produced from the hydrolysis of the ester. The removal efficiency of the filter cake was nearly 100% and the return permeability was about 100%, when using a ratio of polylactic acid to calcium carbonate 3 to 1. The decrease in the CT number of the core after the removal process indicated that the filter cake was completely removed and no formation damage occurred. This paper will discuss the development of this new drilling fluid and will give recommendations for field applications.