bluuebunny/crossref_metadata_2025 huggingface dataset:
Remediation of Hazardous Materials with an Emphasis on NORM
Authors: Sharkey Megan A. , Burton James M.
Published: June 2009

Everyday, Naturally Occurring Radioactive Material (NORM) is produced and is a hazard for the oilfield industry. The oilfield industry releases NORM from the sub-surface to the surface during the production processes that produces water, oil and gas. Most often NORM is found in production tubing, piping, and equipment, such as tanks or heater treaters that can build up scale or store fluids. Leakage or a simple work-over can get this on the ground or on a workers clothing. If the NORM solid is inhaled or enters a human body orally, it can cause the worst type of cancer.

There are multiple ways to handle NORM waste efficiently, safely, environmentally, and cost efficiently. Handling of NORM begins during the remediation of a well or site equipment, then the waste should be minimized and securely contained and, lastly, responsibly disposed. Removal of the scale or sludge from pipe may be done using either a "Pipe cleaning Machine" or inside a "decontamination booth". Each uses high pressure water blasting for removal of NORM and collecting the sub sequential waste in different catch systems. Waste collected may be minimized by separating out the wash water then chemically and mechanically fluidizing the NORM using a "No Moving Parts Grinder", "Sand Wash Unit", or a Gasification unit. Minimized or non-minimized wastes have multiple disposal options including land-farm (dilution), down-hole disposal, and encapsulation in an impermeable cell. A recent technology referred to as gasification minimizes, disposes, and produces energy in the same system. Disposal methods vary in safety and distance from public. Further, remediation, minimization, and disposal options drastically vary in cost efficiency and long term safety.
Importance of Mercury Injectiion Capillary Pressure (MICP) Measurements at Pseudo Reservoir Conditions
Authors: Mitchell Phil , Al-Hosani Ismail , Mehairi Yousuf Al , Kalam Mohammed Zubair
Published: June 2009

Laboratory Special Core Analysis (SCAL) tests are designed to mimic measurements on representative reservoir cores at representative test conditions. These ‘rescon’ tests are however difficult to conduct, and generally cause many uncertainties in test design and numerous experimental artifacts for acceptable interpretations. Success has been achieved primarily in water-oil rescon displacements with live crude at full rescon and in gas process displacements (secondary gas injection, tertiary gas injection and WAG/SWAG). Capillary pressure (Pc) measurements form the basis of SCAL evaluation, and hence the importance of deriving Pc data as accurately as possible from different types of tests.

High pressure mercury injection tests were performed on selected rock types from a prolific carbonate reservoir, and results compared with that typically done at the ambient pressure conditions. Reservoir core samples from same depths were also investigated using multi-speed centrifuge at a high temperature and reservoir net confining stress. Additional core characterization data were obtained using NMR T2 relaxation times at stressed experimental conditions.

Primary drainage Pc and pore throat distribution data derived from mercury injection showed differences for tests at ambient conditions when compared with stressed conditions. The detailed study involving several rock types showed differences in entry pressures and the distribution of pore throat sizes, with the latter showing much narrower and prominent peaks at stressed conditions. These results were compared with centrifuge measurements on reservoir core plugs from similar depths at the same stresses, and confirmed the trends observed. Variations in MICP and centrifuge based Pc is explicable from different underlying principles in the techniques.

The Pc data at pseudo reservoir conditions enhances the confidence in validating the reservoir rock types and the ensuing static model development. Reservoir core measurements at representative test conditions underlie the model development to assess STOOIP and subsequent recovery schemes.
The Development of an Integrated Prioritization and Tracking System to Insure the Integrity of Safety Critical Systems
Authors: Cooke Steven , El Dine Ahmed Ezz
Published: June 2009

A key tenet of Integrity Management is the appropriate focus on critical equipment systems. Many of the lapses in system integrity are the result of improper allocation of resources to less critical areas. A system to clearly identify and communicate criticality as a decision-making criterion regardless of the specific application (operations, inspection, or maintenance) is needed to assure that the ‘right thing is done at the right time’.

ADGAS has developed a HSE Critical Equipment System (HSE-CES) in collaboration with a consultant that links equipment designations that are ranked as critical from the HSE point of view, to inspection and maintenance routines and affected equipment systems. This system is designed to maintain the integrity of critical systems. KPI's are developed to provide both leading and lagging indicators for the effectiveness of this system. The key innovations are the identification of equipment individually instead of as overall systems, and the common interface to operations, inspection and maintenance functions. This allows better coordination of integrity maintenance efforts and an early warning for areas requiring more immediate attention. Components are linked to the larger systems that they protect to provide a better evaluation of the overall integrity risk rather than simply a component failure risk.
Steam Injection into Fractured Carbonates – The Physical Recovery Mechanisms Analyzed and Upscaled
Authors: Bychkov Andrey , Verlaan Marco , Boerrigter Paul , van Heel Rijswijk Ton , van Dorp Johan
Published: June 2009

Conventional displacement methods such as waterflooding do not work effectively in densely fractured reservoirs. The high fracture permeability prevents significant pressure differentials across oil bearing matrix blocks leading to negligible oil drive. In such reservoirs one has to rely on natural mechanisms like capillary imbibition or gravity to recover oil from the matrix rock. In Middle East fractured carbonates, the matrix rock is commonly oil-wet or mixed wet and only gravity drainage remains a feasible process. However, permeabilities are usually low, <10 mD, resulting in low gravity drainage production rates with high remaining oil saturation and/or capillary holdup.

Thermal EOR methods have the potential to improve the gas oil gravity drainage (GOGD) rate and ultimate recovery. For shallow fractured reservoirs, it is feasible to inject steam into the fracture system, in the process known as Thermally Assisted GOGD (TAGOGD). Steam will condense as it contacts cooler matrix rock, resulting in a steam front that develops in a stable way through the fractures. Conductive heating of the matrix will result in oil expansion, viscosity reduction, solution gas drive and stripping effects. No viscous pressures are building up, and steam drive does not occur. For reservoirs containing viscous oil, the viscosity reduction effects are most important. When steam is injected in light oil reservoirs, solution gas drive and stripping effects potentially become dominant.

In this paper we analyse the effect of the different recovery mechanisms. We discuss the results of stack simulations for light oils and for a range of fracture spacings with reference to our previous results on viscous oils. We compare single-porosity simulations of a fracture-matrix stack system with dual-permeability simulations. The dual-permeability modeling requires special techniques to capture transient effects.
Recent Innovations and the Importance of Planned Maintenance & Inspection Procedures
Authors: Warriner Duncan
Published: June 2009

The considerations made during the design phase of a pig trap can be vitally important in ensuring that the operational unit is both practical and safe to use. Primarily we explore what we actually expect from a pig trap and what it is required to do. In addition we discuss the role of the various key trap components and how these differ for the different trap types.

In understanding what a trap does and what it consists of we look at innovations to the basic trap design and how this can further solve some of the practical design issues discussed.

Finally having designed a trap to cater for the known requirement we must of course understand the importance of looking at what is often a forgotten item. We must understand the value in identifying any issues and ultimately maintaining the equipment to protect our assets and more importantly life.
Interpreting Different Seismic Data Cubes Leads to New Insights for an Offshore Field, Abu Dhabi, United Arab Emirates
Authors: Khouri Naeema , El Awawdeh Raed , Shevchek Z J , Harris Christopher , Reilly J M , Zelewski Gregg , Gombos Andrew , Johns Mary
Published: June 2009

A series of new 3D seismic data reprocessing projects have provided the opportunity to develop an upgraded interpretation for a major Middle East offshore oil field. Using a number of different seismic attributes an improved structural and stratigraphic interpretation has resulted in significant changes that will be incorporated into a new generation of geologic models for simulation modeling of the Kharaib carbonate reservoir. The changes include a new fault framework that will influence future well placements and the overall development plan for the field.

Near-, mid-, far-, and full-stacks, spectral whitening and spectral decomposed data show different degrees of stratigraphic and structural resolution. The full reprocessing of a test cube included a separate processing flow for hydrophone and geophone data. The attributes of these individual cubes as well as the combined cube were studied. New insights were gained into remaining multiples in the data sets as well as differences in fault images.

Due to the use of multiple volumes and attributes the interpretation required a disciplined approach in the generation of new horizons and fault identification( Fig. 1). Criteria used for the fault definition for each data cube were clearly defined at the beginning of interpretation. From the new improved data, unsmoothed automated horizons were picked which led to better identification of small faults using horizon-based attributes. The new data allowed identification of pervasive NE-SW and N-S faults in parts of the field and to subdivide major faults into smaller faults at different stratigraphic levels. The new structural framework has been incorporated into the full field geologic models. Based on these encouraging results the same interpretation approach will be applied once a full-field reprocessing project is completed. Fig. 1Multi-volume interpretation approach
Experiences and Benefits Gained through Implementation of the First Intelligent Field in Saudi Aramco (QATIF Field)
Authors: Al-Dossary Faisal M. , Al-Ghamdi Abdurahman A. , Al-Ahmari Abdulrahman S.
Published: June 2009

Qatif field is the first intelligent field in Saudi Aramco equipped with measurement, communication, control and software allowing real-time automated field management. The Qatif field is equipped with automated remote controls and surveillance systems due to its complex reservoir fluid characteristics, including high H2S concentrations up to 16% mole fraction.

Initially twenty multiphase flow meters were installed at Qatif field 22 drill sites, testing 96 wells. One of the MPFM units tests sixteen wells from three different producing reservoirs. (PVT) reports based on black oil models were initially used, but did not match the fluid characteristics due to the H2S presence in the produced gas, in addition to the sulfur substance in the produced fluids. The initial tests using the black oil model were showing water cut as high as 60% on wells known to have no water. Using the limited number of available PVT reports, we have generated simulated generic PVT reports for each reservoir.

To facilitate real-time well bottom pressure data and reduce the wireline interventions to collect these data, tandem gauge permanent downhole monitoring systems (PDHMS) were initially installed in 29 wells. Data was collected and used to support well flow optimization efforts to determine the maximum well deliverability, based on current BHP conditions. Further, these data supported ongoing simulation efforts within the three reservoirs through the generation of real-time isobaric maps to optimize production/injection strategies. Problems with these PDHMS included six of 29 that failed prematurely due to downhole cable failure. These gauges eliminated 62 wireline interventions a year with savings of $350M.

Safety in Qatif field is a major ongoing concern since the field has high H2S concentrations. Well sites and associated flowlines are equipped with the following: state of the art emergency shutdown systems (ESD), wellhead and valves use programmable logic controls (PLC), H2S sensors and remote controls 3. This equipment contributed to the field's zero safety incident record for the past 4 operating years.

The use of the I-Field concept has reduced field operational expenses as well as improving the overall well surveillance activities. During 2007, the operating cost in the field was reduced by over $ 1million and any lost production avoided by employing I-Field intelligent fields for the well surveillance activities. The reservoir models are being updated real time to enhance well placement as well as to optimize existing well operational strategies. Remote well controls have reduced manpower and conventional equipment requirements to operate the field while maximizing well surveillance activities.
Material Selection for Downhole Sour Environments
Authors: Moosavi Ali N , Rumash Khalid , Kadri Mostafa
Published: June 2009

The steep rises in price of crude and gas have led operators to increase their production, much of it through secondary recovery. The increase in production has resulted in increases in water cut and H2S which, together with other corrosive elements such as CO2 and chlorides, have caused serious concerns regarding safety and corrosion. The traditionally used steel OCTG suffer failures within a relatively short period of operation in these environments. Therefore the use of corrosion resistant alloys (CRA) is set to increase over the coming years. The cost difference between the lower and higher end of CRA can be very substantial. The traditional material selection approach has heavily depended on the use of standards and desktop corrosion rate predictions. However the confidence level with this approach is limited. A comprehensive and innovative program has therefore been adopted to address this issue. Our approach has been two fold: first we designed and manufactured a special downhole coupon holder in order to expose a number of different CRA material in a selected number of our reservoirs. Secondly, we carried out a comprehensive program of corrosion tests on a range of materials in a variety of our reservoir conditions simulated in the laboratory. The combination of field, lab and desk-top evaluation enables us to select the most technically suitable and cost effective material for each specific environment.

A total of 14 alloys from a number of manufacturers have been tested. These ranged from the L-80 carbon steel (used as reference) to the lower end CRA such as 13Cr and Super 13Cr to mid range CRA such as duplex stainless steel ton the higher end nickel-chromium alloys. The results have been very encouraging. Ten out of 14 materials tested exhibited insignificant levels of general and localized corrosion (pitting and crevice). The four which suffered corrosion higher than this level were the L-80 carbon steel reference material and most of the 13Cr alloys. Encouragingly, all the Super 13Cr alloys passed all the corrosion tests in all the environments satisfactorily. Even in the environmental cracking tests the super 13Cr alloys were successful in the majority of the tested environments. These are at the cheaper end of CRAs and using them instead of Ni-Cr alloys can make very substantial savings for the operating company, as well as proving a material which is technically far superior to the traditionally used L-80 carbon steel and provides a much longer operating life.

The field testing results were even more encouraging with the Super 13Cr alloys not suffering from cracking in any environments and, apart from the most aggressive one of the eight field testing environments, they did not suffer from any significant corrosion or pitting.

A classification of the tested alloys by test condition, based on the laboratory results is presented. This shows that for every one of the downhole environments that we have tested, there are a range of acceptable materials available.
Maximum Reservoir Contact Wells: Six Years of Performance-Lessons Learned and Best Practices
Authors: Salamy Salam , Al-Mubarak Saeed , Al-Mubarak Hassan , Al-Dawood Naseem , Al-Alawi Ahmad
Published: June 2009

This year marks the sixth year anniversary of the birth of the Maximum Reservoir Contact (MRC) wells in Saudi Aramco. The outstanding performance of 99 MRC wells drilled to date in different fields reflects the impact of MRC wells on improving well performance, enhancing recovery and reducing unit development costs. In view of this performance, the use of this technology will continue to be on the rise.

This paper will highlight the drivers, selection criteria, and lessons-learned from the MRC wells. It will further highlight cases of how MRC wells became the cornerstone in optimizing the development of tight reservoirs and in re-engineering mature ones. In addition, the paper will highlight the impact of MRC wells on rate sustainability and on increasing off-take levels by up to five times when compared to vertical and single lateral well completions. MRC wells not only targeted new development wells, but also extended to workover programs where low performer and dead wells were converted to MRCs. Results were phenomenal in terms of improving well productivity and delaying water and gas breakthroughs-thereby improving sweep.
Optimizing Production in Maximum Reservoir Contact Wells with Intelligent Completions and Optical Downhole Monitoring System
Authors: Al-Arnaout I. H. , Al-Buali M. H. , Al-Mubarak S. M. , Al-Driweesh Saad M. , Zareef M. A. , Johansen E. S.
Published: June 2009

In today's drive to improve well production and performance, more innovative methods are continually being implemented to enhance well productivity and reservoir management. By increasing reservoir contact and applying fit for purpose technologies, increased production can be attained at lower drawdown. This can be accomplished by the effective implementation of multilaterals wells. In multilateral wells equipped with active downhole control valves and downhole measurement-devices, monitoring and managing the production from each lateral is achievable. These capabilities will enhance well performance and allow better sweep; hence better recovery.

This paper describes the design, completion, commissioning, and operational experience of the world's first well equipped with intelligent completion combined with fiber-optic monitoring capabilities. Well-A is a trilateral MRC well with more than 5 km of total reservoir contact. The monitoring system for each lateral includes an optical flowmeter and pressure and temperature gauge. The readings of the flowmeter were compared to the readings against the conventional testing facilities. Production tests were conducted with various combinations of downhole valve positions for each of the three laterals to determine the optimum combination. The pressure and temperature gauges yielded excellent measurements as they were verified against conventional pressure and temperature measurements. The downhole flow rate measurements were assessed against conventional rate measurements and demonstrated acceptable results across most downhole valve positions. A comprehensive review was conducted on the optical flow meter capabilities to provide better understanding; hence, facilitate further enhancement to the technology and better production optimization capabilities. The review was utilized to develop a new system that provides better capabilities across all valves positions.
Installation for Pressure Reduction of Hydrocarbon Gases in a Near Isothermal Manner
Authors: Valente Antonio
Published: June 2009

New equipment designed for achieving the pressure reduction of Hydrocarbon gases in a near isothermal manner with the simultaneous recovery of its elastic energy lost during pressure reduction thermodynamic process. The equipment is consisting on utilizing a Tesla turbine which rotor is composed of several parallel plane discs rotating by boundary layer effect, induced by the moving gas drag when spirally passing parallel to those discs, associated with an electrical power generator.

During experimental tests it was found that the gas to be processed suffers a pressure reduction, by loss of energy transmitted to the rotor, in a near isothermal manner contrary to the usual equipments utilized in the actual state of the art.

Taking advantage of the said discovered singularity the equipment will be applied for pressure reduction of Hydrocarbon gases, without the temperature reduction associated if utilizing the Joule-Thomson effect and in addition will generate energy. It will also be applied in Hydrocarbon gas liquefaction, with in a first step of near isothermal pressure reduction complemented by a cryogenic stage of liquefaction where the energy required will be derived from one generated on the first step.

In the actual energetic conjuncture, this equipment will provide a pressure reduction thermodynamic process for gas pressure reduction stations in gas transmission pipelines that does not require the supply of external energy for re heating, with the associated cost and pollution and on top of it, recovers in the form of electrical energy part of the elastic energy lost by the gas.

It is also significant the application of this equipment in gas liquefaction plants, since it will achieve the desired results with lesser energy consumption.
Enhanced Oil Recovery Pilot Testing Best Practices
Authors: Teletzke G. F. , Wattenbarger R. C. , Wilkinson J. R.
Published: June 2009

Enhanced oil recovery (EOR) implementation is complex and successful applications need to be tailored to each specific reservoir. Therefore, a systematic, staged evaluation and development process is required to screen, evaluate, pilot test, and apply EOR processes for particular applications. Pilot testing can play a key role in this process. Prior to field testing, pilot objectives need to be clearly defined and well spacing, pattern configuration, and injectant volumes determined.

This paper outlines a staged approach to EOR development and focuses specifically on pilot testing best practices. These best practices were derived from ExxonMobil's extensive piloting experience, which includes over 50 field pilot tests covering the full range of enhanced oil recovery processes. Topics covered include: 1) determining whether a pilot is needed and defining pilot objectives, 2) considerations for successful pilot design, 3) types of pilots and their advantages and disadvantages, 4) tools and techniques for assessment of key reservoir mechanisms, and 5) minimizing uncertainty in pilot interpretation. Key issues that are often addressed by pilots are discussed, including areal sweep and conformance, gravity override, viscous fingering, and loss of mobility control. Also included are aspects of instrumentation and measurements in pilot injection, production, and monitoring wells. Several ExxonMobil piloting examples are used to illustrate the best practices, including a single-well injectivity test, an unconfined pilot with observation wells, a small-scale confined pilot, and a large-scale multi-pattern pilot.
Utilizing Online Water Detection to Automate Production Management
Authors: Mohajer Kam
Published: June 2009

In today's competitive energy market there is a tremendous emphasis on cost saving and productivity at all levels of the industry. Online water detection provides vital real-time information regarding water concentrations in hydrocarbons with numerous beneficial applications. Specifically, with the high volume of produced water in today's wells, utilizing oil water detectors or OWD's to automate production management creates efficiencies in terms of time, cost and vital man hours, and OWD's incorporating microwave technology demonstrate extreme accuracy even at the highest water concentrations.

Currently, production is manually managed by the rotation of "producing" and "shut-in" wells. This system creates a great deal of waste and cost both in terms of produced water and energy utilized. The installation of OWD's on each well creates a continuous flow of data specific to each well that can be combined with separation and flow data, then sent to a remote dashboard for monitoring.

Utilizing such a system gives the production operations team the real-time, site-specific data required to automate and maximize efficiencies throughout the production process. In particular, it provides the knowledge required to shut-in wells with high water production levels and concentrate production on those wells currently producing higher concentrations/volumes of oil and to do so on an as-needed basis. What's more, this process can be informed and enhanced by a wide variety of criteria specific to your needs such as oil-water separation capacity, water-disposal capacity, flow rates, etc.

The efficiencies created in production management are particularly vital in today's production climate where current levels of demand increase the pressure and importance of every producing well. At the same time, these wells are producing record amounts of water. Higher produced water concentrations combined with increased demand create an imperative for maximizing both the efficiency and automation of production.
Facies Modeling Using Multiple-Point Statistics: An Example from a Carbonate Reservoir Section Located in a Small Part of a Large Shelf Margin of Arabian Gulf, UAE
Authors: Arslan Izzet , Ribeiro Maria Teresa , Neaimi Mohamed Al , Hendrawan Irfan
Published: June 2009

A new breakthrough in reservoir modeling is using Training Images (TI) with Multiple Point Statistics (MPS). A TI is a structural image of a reservoir layer or stratigraphic time interval, which represents all the relevant events (e.g. facies) at a time independently from a real location. Therefore, the Tl's capsulate much broad geological sense with conceptual patterns or multiple joint relations beyond the traditional geostatistics where it may merely offer two-point correlations (e.g. variograms) with sparse well data.

Each time sequence presents a transgression within Arabian plate along hundreds of km's distance length one would not see the whole sequence of a platform (e.g. lagoon, ramp and shoal deposits) through a relatively small reservoir area (30km × 30 km). This brings a common challenge in facies modeling of carbonate reservoirs regarding lateral changes in deposition settings that are rarely crossed along the small scale reservoir sequences although a diversity of facies types can be observed vertically.

The Arabian Gulf plate reservoir of Lower Thamama around Abu Dhabi was studied to understand how a relatively limited reservoir area was deposited through the help of Tl's. A rock-type study based on core and log data was compiled, and 23 facies types varying vertically were identified. Tl's were drawn for each time interval between high resolution sequence stratigraphy (HRSS) picks. It was not eligible to drive properties through seismic attributes since the seismic attributes were weak for tuning the facies heterogeneity. The analogs, representing the depositional strata sketch were mapped with outcrop data, core descriptions and solid geological knowledge of the reservoir. Given these conceptual images conditionally, all possible scenarios of the deposition were simulated with MPS algorithms. Uncertainty analysis was also performed to infer the variability of the different TI's.
Improving Lifecycle Project Delivery Through Better Decision-Making Under Uncertainty
Authors: Yawanarajah Shareen , Williams Jevon , Carrell Ken , Webb Tom , Cox Mike
Published: June 2009

The total value realized from an asset depends on how well it is managed throughout its lifecycle, from exploration to early development to abandonment. Decisions in all phases of field life cycle depend on the proper use of uncertain information. Shortcomings in uncertainty management are primarily a problem of organizing work processes, providing access to consistent information, and managing projects across organizational boundaries. A key critical success factor is also strong inter-disciplinary decision-making in all decision domains.

Recognising this, in Shell, within the development-planning phase of the field life cycle, we have developed two key programmes for New Projects that integrate decision-making under uncertainty with technologies to mitigate risks, and skills and workflows to implement them.

In the first programme, we streamline the activities involved in planning the field development. This includes simplifying project management responsibilities, managing subsurface uncertainties more effectively and enabling work to be done more collaboratively. Using a tool that was co-developed with Schlumberger, we have been able to make visible to the key stakeholders/decision-makers fit for purpose work plans, track milestones and action items, as well as capture "as-is" thinking, work-in-progress data/documents and team decisions throughout the life cycle.

In the second programme, we have developed a company-wide methodology that brings Smart Fields elements into project design planning. It identifies the most appropriate technologies to mitigate operational risks and enables their application. The methodology, referred to as Smart Fields Initial Screening, uses a structured process to match the appropriate Smart Fields integrated solutions to the specific needs of the project. This is done for all key components of the production system.

The new ways of working are enabled by bringing together -- in one room or virtually -- skilled people for multi-disciplinary discussions to jointly interpret the information to make fast, good decisions to improve project delivery and enable better field performance.
Neural Net Prediction of Porosity From Seismic Successfully Used to Improve the Reservoir Model Away From Well Control
Authors: Zaabi N. Al , Soroka W. L. , Abousetta A. A. , Kaya A. S.
Published: June 2009

To maximize recovery from carbonate reservoirs it is necessary to build models that include as much detail as possible about the variations in reservoir properties. Due to the heterogeneous nature of many carbonate rocks the standard techniques of building a porosity model by using well data alone can produce models that do not accurately represent the true subsurface geology. Seismic data is another source of information that can provide valuable details about the changes in porosity away from well control. An inversion was performed on a seismic volume over an Abu Dhabi field to generate an acoustic impedance model of the reservoir. Using the acoustic impedance, available well data and other seismic attributes a neural net project was performed to produce a porosity volume. The porosity volume was in agreement with porosity log data at the well locations and showed lateral porosity variations that could be used to update the porosity in the reservoir model. A porosity volume was also calculated from the inversion acoustic impedance results using a porosity to acoustic impedance relationship derived from the log data. The inversion porosity model was used as and additional control on the neural net porosity from seismic results and for validation.

The porosity from the neural net project was transferred to the reservoir model building software and successfully used to validate and update the porosity in the reservoir model away from well control. The revised porosity model more accurately showed the affects of faults on porosity and porosity changes due to digenesis and facies changes. The added details and more accurate lateral variations in reservoir porosity obtained from seismic information has the potential to produce more accurate and reliable simulation models showing the dynamic behavior of the reservoir.
Geosteering Optimization in Thin Carbonate Reservoirs
Authors: Ramos L. , Ali S. , Maskary S. Al , Abou-Mostafa S. , Mirto E. , Padiav P. , Aki A.
Published: June 2009

Targeting more complex and challenging reservoirs in terms of stratigraphy and structure, makes improved geosteering precision a necessity. This is particularly true when targeting thin permeability streaks or avoiding thin dense layers in highly heterogeneous reservoirs. The challenges are even greater when these thin reservoirs are highly faulted and the risk of missing the target is higher. Applying a proactive approach for well trajectory optimization while drilling and using the most recent logging while drilling (LWD) technology such as distance to boundary measurements, real-time image logs integrated with other LWD logs and 3D structural/properties models, it is possible to maximize the wells value. Deployment of these new technologies allows tracking the "sweet spots" of the reservoir more efficiently as uncertainties related to the dip, thickness of the reservoir and fault/fracture occurrence are better managed. This approach saves time and money by reducing the chances of missing reservoir targets and therefore the need to sidetrack or drill a complete new well. Another benefit from these procedures is the well accessibility which is highly improved due to an increased in the borehole smoothness, which is achieved through better control of the well trajectory. In this paper, several examples will be shown for different scenarios in different oil fields/reservoirs in Abu Dhabi, U.A.E.
Using a Dynamic Coupled Well-Reservoir Simulator to Optimize Production of a Horizontal Well in a Thin Oil Rim
Authors: Nennie E. D. , Alberts G. J. N. , Peters E. , van Donkelaar E.
Published: June 2009

Stabilization and optimization of production are the key challenges for smart well control. In order to compare the effectiveness of different control strategies, a simulation environment can be used. To study and control the effects of for instance slugging, gas coning and wax deposition, both reservoir dynamics and the dynamics of multi-phase well flow have to be taken into account in such a simulation environment. In this paper we use a dynamic coupled well-reservoir simulator to identify instabilities of a field case and test a control strategy to mitigate gas coning and wax deposition.

The dynamic simulation environment has been developed within the research framework of the ‘Integrated System Approach Petroleum Production’ knowledge center of TNO, TU Delft and Shell. This simulator has been validated with field data of a horizontal well located in a thin oil rim, suffering from gas coning and containing a crude which has a high tendency to wax. With the help of the simulation environment it was possible to understand the production instabilities observed in this well and to determine a control strategy to stabilize and optimize its production. The results of the coupled well-reservoir simulations are presented and the phenomena that are most likely to cause the production instabilities observed in the field are identified.

In production optimization the current status is to use separate dynamic well and reservoir models. In case of significant reservoir-well interaction this approach gives a non-realistic production forecast. This project gives a clear indication that, when using a coupled simulation on a real field case, a better understanding of the instabilities and therefore a more accurate production forecast and a better control strategy can be designed.
Yardstick for Talent Pipeline in Oil and Gas Industry in India
Authors: Chatterjee Urmila
Published: June 2009

Talent Management is the method of nurturing the employees' potential, aptitude and ability towards the betterment of the self, keeping in view the goals of the company. The talent crisis facing today's corporate world including the hydrocarbon industries in India, is an outcome of the competition amongst different business houses to tap and retain the best. In order to nurture and build talent it is necessary to interface and pass on knowledge from more experienced employees to less experienced employees. The components of this talent pipeline are Management Development Programs (MDP); On-Job-Training (OJT); Interfacing Knowledge (IK); Talent Search, Relationship, Skill and Trust Building (TRUST); and Inspiring Leadership Qualities (ILQ). In this paper we propose a new quantitative measure called Pipeline Index to judge the progress of the talent chain and provide a methodology for its measurement. This is calculated as W × H where the weightage W is highest at the top level of management and H is the number of hours per week being spent by an employee in talent pipelining. A questionnaire was prepared and distributed to compute the Pipeline Index for a large oil and gas company in India. The response to the questionnaire is used to compute the Pipeline Index over the last 5 years for this company. Evaluation of the results shows both the key areas of strength of the company and the areas where the talent pipeline needs to be reinforced. The analysis shows that this company suffers a slight decline rather than a desirable growth of the talent pipeline over the 5 year period 2004–2008. We consider ‘Giving’ and ‘Receiving’ as two ends of the talent pipeline. The shortfall between ‘Giving’ and ‘Receiving’ is defined as the Talent Gap. Our study reveals that the talent gap is the result of employees spending time in guiding others but where the guided persons do not believe that they have benefited. The proposed definition of Pipeline Index and the questionnaire based method of its evaluation could be applied to any company and may be used to compare the talent pipeline for different companies.
Impact of the Effective Implementation of Project Integrated Quality System (IQS) From Early Stages of Design Development
Authors: Daoud Mohamed
Published: June 2009

Over the past 25 years, demands for quality have grown dramatically. The main factor behind this growth has been failure of plant and components in service.

Historically, the term quality has been associated with things like checks and inspections. Control of quality was only a simple matter of random inspection, i.e. the acceptance or rejection of finished products. It is now recognized that quality can not be inspected in; they must be managed in. must be designed, built into the product and controlled in systematic manner.

It is not possible to manage something which is poorly defined. Quality has come to mean: Conformance to Requirements.Conformance to specifications and standard.Fitness to use and cost.
Low Production Tester (LPT) - A Viable Solution for Marginal Wells Testing
Authors: Hodgson Paul
Published: June 2009

At Petroleum Development Oman LLC (PDO), well testing has successfully been carried out for the past few years utilizing multiphase meters. Although this technology provides many benefits to PDO, the meters, being basically venturi based, had a low flow limitation of 20–25 m3/day for gross liquid measurement. So in the past, these low flow wells used to go largely unmeasured or were measured using the older, conventional testing systems, which were not very reliable.

In order to overcome this issue, and provide a well testing solution for wells producing less than 20 m3/d, the operator of PDO's Mobile Well Testing Units was approached to try to develop a prototype, which could be tried in PDO under their existing Mobile Well Testing Contract. They came back with a skid based, mobile unit in October, 2006, that had a range of 3–25 m3/day of gross liquid flow as standard and could extend its range up to 100 m3/day. The unit measured 0–100 % water cut and could operate in 0–100% GVF conditions.

Following introduction of the unit in the PDO South concession areas, testing of wells has been carried out where multiphase meters have not been successful, and this has not been limited to wells producing less than 20m3/d as per the original intent but also for testing wells where the produced oil viscosity was outside the operating parameters. Results have been very favorable, with practically a 100% validation rate. The unit was thus deemed acceptable to use as an additional well testing tool and was subsequently included in the PDO Mobile Well Testing Contract, awarded in April 2007. The unit gives good reliable data for wells with low production rates and can also be used where high viscosity becomes a problem for testing by other means.
Extended Binomial Trees for Real Options Valuation in E&P Projects
Authors: Galvis C. F. , Villarreal J.
Published: June 2009

The following paper addresses the limitations of the Binomial Tree Approach for Real Options Valuation (ROV) when used as a direct extension from Financial Options Valuation (FOV), since the strong assumptions that support the theory do not always apply to investments in real assets. Subsequently, a solution for these problems is proposed using an extension of the binomial approach, which complies with the conditions that this theory imposes on Financial Options Valuation, and hence, on Real Options Valuation.

The proposed approach, the Extended Binomial Trees (EBT), permits sign changes to occur inside the underlying asset's tree, unlike the traditional binomial approach, and prevents skewness and kurtosis from happening in the rate of return distribution. This methodology is then presented using as framework the valuation of redeveloping the Sardinata field, in Colombia, and the results are presented in a comparative chart along with the ones obtained by means of the traditional binomial approach.
Experimental Measurement and Modeling of Asphaltene Precipitation in Crude Oil
Authors: Nikookar M. , Omidkhah M. R. , Pazuki G. R. , Sahranavard L. , Roayaei E. M.
Published: June 2009

In this study, at first the amount of asphaltene precipitation produced by adding different ratios of n-alkanes (n-pentane, Hexane, n-Heptane, n-nonane) into an oil sample obtained from one of Iranian oil fields has been measured. The obtained results were compatible with the results of other researchers. Meanwhile, the reversibility of asphaltene precipitation process has been investigated as an important subject in this phenomenon. Then, by using the experimental data and optimization, the scaling equation's coefficients were calculated and then the amount of asphaltene precipitation and the onset point have been obtained by the scaling approach. Finally, the obtained results have been compared with the experimental data and the model's accuracy was approved.
Azimuthal Anisotropy Analysis for Fracture Reservoir Characterisation: Supergiant Field, U.A.E.
Authors: Ribeiro Christophe , Reiser Cyrille , Al-Shekaili Fatema Saeed , Al Nahhas Mohamed Samir , Boekholt Martin
Published: June 2009

A fracture characterization feasibility study is conducted over a subset area of an onshore supergiant carbonate field within the Abu Dhabi emirate, using P-wave azimuthal anisotropy analysis. Multi-azimuth seismic data are pre-conditioned using Shell-proprietary filtering, CGGVeritas-proprietary geostatistical decomposition and amplitude balancing to effectively remove the noise component from the data and amplitude artifacts due to near-surface conditions. A 3D post-stack stratigraphic inversion is performed to obtain robust azimuthal acoustic impedances that are converted into anisotropy attributes. The study proves that seismic anisotropy can be attributed to the fault pattern in one layer of the main producing reservoir, and to gas injection pattern in another layer of this reservoir.
A Diagnostic Toolkit to Detect Compartmentalization Using Time-Scales for Reservoir Mixing
Authors: Muggeridge Ann H. , Smalley P. Craig
Published: June 2009

Unidentified reservoir compartmentalization through faulting or depositional heterogeneity can have a profound, usually adverse, effect on oil or gas recovery. Thus it is vital to characterize reservoir compartmentalization as early as possible in field life, ideally during appraisal.

One signature of compartmentalization is the detection of variable fluid properties (e.g. pressure, fluid contacts, oil or water composition) in different parts of the reservoir. Such spatial variations arise during the burial, structural and filling history of the reservoir, and gradually equilibrate through time. However such spatial variations may persist simply because sufficient time has not yet elapsed for that property to equilibrate, potentially leading to false-positive diagnoses (variations are present but relate to insufficient mixing times, not compartmentalization). In other cases, mixing can occur so rapidly that fluid variations have already mixed, leading to potential false-negative diagnoses (variations not present because mixing has occurred quickly in spite of compartmentalization that will affect the production timescale). It is thus vital to incorporate an understanding of reservoir mixing timescales into the early diagnosis of compartmentalization.

This paper provides simple analytic expressions for estimating the time taken for tilted contacts and spatial pressure or compositional variations to return to their equilibrium distribution, as a function of reservoir thickness, length, porosity, permeability, fluid viscosity, density and compressibility. These form a simple and practical diagnostic toolkit.

Use of this toolkit reveals many cases where lateral compositional variations do not indicate compartmentalization but result from incomplete mixing due to very slow molecular diffusion. In contrast, pressure may equilibrate across a micro-Darcy, permeability fault in 100,000 years, so uniform pressure does not necessarily guarantee good reservoir communication on a production timescale. Compartmentalization can only be accurately identified and quantified through integration of different reservoir data and consideration of their very different timescales for mixing.
Subtle Faults in Carbonate Reservoirs
Authors: Pion Jacques , Vesseron Marc , Dugoujard Thierry
Published: June 2009

Subtle or sub-seismic faults in carbonate reservoirs are often mentioned in the geosciences literature but using them as hard data to qualify reservoir connectivity is generally not an accepted standard. The present paper illustrates with field examples that even faults with very small throw (<3m) can backscatter energy, that this energy appears on seismic displays as a consistent interference pattern similar to the response of thin beds. The paper further suggests a filtering method to distinguish subtle faults from image processing artifacts, and proposes a workflow allowing their integration into reservoir models, either as connectivity enhancers related to the presence of open fracture networks in the vicinity of fault surfaces or as indications of faults with minor throws acting as buffer or barrier zones.