bluuebunny/crossref_metadata_2025 huggingface dataset:
Water Saturation Modeling in Khafji Carbonate Reservoir
Authors: Al-Otaibi Mohammad H. , Khamatdinov Rafael , Al-Khaldi Nasser , Abdelrahim Rabei , Bouaouaja Mohamed
Published: November 2012

Within an oil reservoir the water saturation height functions can vary strongly, especially for carbonate rocks. These variations can be significant and difficult to estimate. The amount of hydrocarbons in place, the prediction of recoverable oil, the recovery process and the future plans of developing such reservoirs depend on many factors, one of which is the accurate modeling of water saturation.

The Khafji carbonate reservoir is a heterogeneous reservoir with two different types of oil: light oil in the top of the reservoir and heavy oil in the bottom of the reservoir. The challenge of water saturation modeling is primarily in the heavy oil zone, where conventional height function techniques produces poor match against measured water saturation logs. Alternative methods were utilized in order to obtain good match in both light oil and heavy oil columns.

A workflow has been created in order to overcome these challenges. Laboratory derived capillary pressure curves were used to establish water saturation height relationships as a function of rock type (RT). Additionally, a Flow Zone Indicators (FZI) analysis was used as a basis for rock typing. Then a J-function derived from capillary pressure data for each rock type or hydraulic flow unit (HFU) was used to generate saturation height function for each RT. The generated saturation undergone via several iterations to match the large span of openhole electric water saturation logs above the free-water level (FWL).

The saturation profile generated by this workflow shows a good match to the measured Sw electric logs, and the calculated fluid volumes are in agreement with company's approved reserves estimation.
Best Practices for Drilling an Open Hole Multilateral Well in a Structurally Complex, Fractured Carbonate Reservoir in Kuwait
Authors: Dutta Bikramjit , Al-Azmi Bader M. , Dutta Abhijit , Fernandes Warren , Zaki Mohammed
Published: November 2012

This paper discusses the critical requirements for successful well planning, landing, geosteering and completion of an open hole multilateral well, with lateral sections of 2,500 ft and 2,200 ft, drilled in a complex carbonate reservoir in Kuwait.

The structure is dominated by four sets of normal faults trending EW, NS, NW – SE and NE – WS. The reservoir is divided into 10 layers, with reservoir quality generally decreasing from top to bottom. The upper layers exhibit good porosity, vugs and molds while the lower layers are mainly mud-dominated with thin, interbedded brittle layers. As there is no significant water-drive mechanism, the development strategy was to maximize production by connecting the natural fracture network through extensive acid stimulation.

The objective was to isolate problematic formations by landing the well below them, while maximizing reservoir contact in the upper layers. This meant intentionally crossing a major NS-trending extensional fault to maximize fracture intersection and therefore maximize the production potential. Well planning and drilling a high quality wellbore to landing point were identified as critical as the four wells drilled previously had resulted in fishing and side tracking in the intermediate section. Optimizing drilling fluid parameters and drilling practices from the lessons learned, and correct selection of rotary steerable system (RSS) and logging-whiledrilling (LWD) tools that led to a successful landing are discussed, as are real-time wellbore placement to maximize production potential using RSS and LWD tools, following best drilling practices and seismic model integration through multi-faulted environment are also discussed. LWD measurements and their integration into the geosteering model, benefits of a high-resolution resistivity image in aiding the identification of fractured zones for stimulation optimization, hole preparation for completion and success and of massive acid stimulation of the open hole laterals using coiled tubing are also discussed.
An Innovative Approach to 3D Fracture Modeling
Authors: Al-Azri Saud , Al-Raisi Muatasam , Bushara Mohamed N.
Published: November 2012

The production of oil and gas from naturally fractured reservoirs requires a thorough understanding of fracture network connectivity. Predicting fracture continuity & connectivity between wells -considering the immense control of multiple parameters on natural fracture behavior at reservoir conditions-remains to be a daunting challenge. A novel approach has been developed to provide a Continuous Fracture Network (CFN) model that honors the temporal and spacial changes of drivers that influence fracture distribution. This technology has been tested and successfully implemented in different carbonate and clastic reservoirs in the region. Complex reservoirs such as Permo-Carboniferous Alkhlata formation, Cambrian Amin formation, and Cretaceous Natih /Shuaiba reservoirs in Sultanate of Oman are examples of successful fracture modelling studies. These case studies are used to demonstrate various steps of continuous fracture characterization in this paper.

Well data, geological properties and high resolution attributes derived from seismic are integrated to build a 3D fracture model. The Fracture Indicators (FI) from borehole images (BHI) interpretation are correlated and ranked with fracture drivers to generate multiple CFN models on a 3D geocellular grid. A fuzzy neural network is used to evaluate the hierarchical effect of each driver on the fractures.

The training and testing of the neural network are accomplished using existing well data. Once the neural network finds the relationship between the drivers and the fracture intensity, it can be used to predict this fracture intensity in every cell of the field since all the drivers are known and available in the entire 3D grid. The model is subsequently validated by drilling data, blind wells and dynamic data. Effective permeability distribution is computed through dynamic calibration of potential well test data with the CFN models. Both fracture and effective permeability models are used to improve history matching, production optimization as well as picking new wells.
Reliable Steady-State Relative Permeability Measurement for Carbonate Rocks from a Middle Eastern Offshore Reservoir with an In-Situ Saturation Monitoring by X-Ray Ct Scanner
Authors: Watanabe Kazuki , Tsuchiya Yoshihiro , Takahashi Satoru , Okabe Hiroshi , Mitsuishi Hiroshi , Al-Shehhi Hamad Rashed , Al-Hammadi Hamdan Mohamed
Published: November 2012

The results of special core analyses using carbonate rocks from a Middle Eastern offshore reservoir are presented based on laboratory and simulation studies. The study aims to obtain reliable relative permeability in an oil-water system under steady-state conditions, and confirm the resulting relative permeability through a simulation study by comparing water saturation distributions along the core at various injection ratios of water to oil. The difficulties in steady-state relative permeability measurements are to determine water saturations and steady-state conditions as only the effluents are measured. To obtain accurate water saturations, we adopted an X-ray CT (Computed Tomography) scanner that allows us to precisely measure porosity and fluid saturation distributions inside cores under reservoir conditions, especially for reservoir wettability. In addition, not only the ratios of water to oil in effluents but also water saturation distributions derived from CT measurements inside the core were used as a measure of steady-state conditions.

Core flood experiments were conducted with periodic measurements at various injection ratios of water to oil. As a result, we obtained eleven relative permeability points with respect to water saturation calculated from CT numbers.

Next, a simulation study was conducted to confirm the relative permeability curves using a core model where CT derived porosity and absolute permeability were assigned based on the core flooding experiments. Results of the core flood simulations with the resulting relative permeability curves show that the simulated water saturation distributions are in excellent agreement with those of the core flood experiments, especially low injection ratios of water to oil. Through laboratory and simulation work, it is confirmed that reliable relative permeability measurements were made by carefully determining water saturations and steady-state conditions with simultaneously measuring the effluents from the core and monitoring the inside core by X-ray CT scanner.
Hysweet® Technology: A Major Progress in Sour Gas Processing
Authors: Zhao Jing , Weiss Claire , Cadours Renaud , Shah Virenkumar
Published: November 2012

Removing mercaptans from sour natural gas is becoming an important issue with the global trend towards more stringent specifications for commercial gases. Amines have been extensively used on account of their ability to meet severe H2S and CO2 specifications and very high acid gas selectivity over hydrocarbons. Amines however present very limited mercaptans removal capabilities, an additional treatment step is generally required to achieve a stringent specification of total sulfur specification in the sales gas or upstream liquefaction plant.

Total, taking advantage of its extensive know-how and experiences in acid gas removal, has developed the HySWEET® processes, for simultaneous absorption of acid gases and mercaptans. This technology relies on a new hybrid solvent formulation allowing limited coabsorption of hydrocarbons and improved energy efficiency. The HySWEET® process has been in operation since 2008, and the entire gas production of the Lacq plant, France is now treated with this new hybrid solvent. The industrial feedback has confirmed not only higher mercaptan removal, but also lower energy consumption when compared to the AdvAmine™ HiLoadDEA process which has allowed for Lacq gas treatment during most of the lifetime of the field.

The development of the HySWEET®DEA process is now completed and ready for commercialization. An optimized design can now be proposed for any application case targeting total CO2 and H2S removal along with a stringent total sulfur specification. Thousands of laboratory measurements (i.e. thermodynamics, kinetics, physical properties) have been used to develop a rigorous simulation tool which relies on rate-based transfer models validated against extensive pilot and operational test-runs.

The HySWEET®MDEA process is under development, for the selective elimination of sulfur compounds over CO2. Improved mercaptan removal and high energy efficiency have been demonstrated during pilot tests. These pilot test results will be later used to validate the prediction of the simulation tool currently under development.

This paper provides a review of the HySWEET® technology: an update on the HySWEET®DEA process and the latest R&D developments of HySWEET®MDEA.
Microbial Enhnaced Oil Recovery by Bacillus subtilis Strains under Simulated Reservoir Conditions
Authors: Gudiña E. J. , Rodrigues L. R. , Teixeira J. A. , Pereira J. F. , Coutinho J. A. , Soares L. P. , Ribeiro M. T.
Published: November 2012

Microbial Enhanced Oil Recovery (MEOR) is a tertiary oil recovery process in which microorganisms and their metabolites are used to retrieve unrecoverable oil from mature reservoirs. Stimulation of microorganisms that produce biosurfactants and degrade heavy oil fractions in situ reduces the capillary forces that retain the oil into the reservoir and decreases oil viscosity, thus promoting its flow. As a result, oil production can be increased. In previous work, Bacillus subtilis strains that are useful for application in MEOR were isolated from crude oil samples. Those isolates were able to grow and produce extracellular biosurfactants at 40°C under anaerobic conditions in mineral medium supplemented with hydrocarbons. In addition, some isolates degraded the long-chain n-alkanes of paraffinic mixtures. Mobilization of residual oil by those isolates was evaluated using sand-pack columns at 40°C. Additional oil recoveries obtained with the different isolates using paraffin ranged from 16 to 31%. The recovered paraffin showed a decrease in the percentage of large alkyl chains and its viscosity was reduced. In the present work, the degradation of long-chain n-alkanes and the mobilization of residual oil by the same isolates were studied using heavy oil. The results obtained confirmed that the isolates were able of degrading the long chain n-alkanes of crude oil, and also additional oil recoveries between 8 and 10% were obtained. Furthermore, for a better simulation of the oil reservoir conditions, a core flooding equipment that can work at the oil reservoir pressure was designed and will be used to confirm the applicability of selected isolates to increase oil recovery. The sampled reservoir consists of sands with an average porosity of 25% and a permeability of 50mD. The oil is paraffinic, with low viscosity, high pour point and a gravity of 25° API, with very low solution gas. The reservoir pressure and temperature are respectively 398-440psi and 40°C.
Water Saturation (Sw) from Logging-While-Drilling Resistivity, Capture Sigma and Core Analysis for ROS Determination in a Giant Middle East Carbonate Reservoir
Authors: Serag El Din Samy , Cao Minh Chanh , Murray Doug , Brahmakulam Jacob
Published: November 2012

Water saturation (Sw) estimates are of prime importance for reserves estimation, reservoir development, and reservoir management. Traditionally, Sw has been derived from the Archie equation with formation resistivity or thermal neutron capture cross-section (Sigma, Σ in stand-alone mode. Either the resistivity or Σ approach requires good knowledge of formation water salinity which can be difficult, particularly in instances of unknown and/or mixed salinities. When resistivity and Σ logs are unaffected by fluid invasion, one can simultaneously compute Sw and salinity from the two measurements as has been done recently using wireline logs acquired in flowing wells.

This paper addresses 2 drawbacks of wireline resistivity-sigma technique: first, it is not always practical to flow the well, and second is the concern about the Σ shallow depth of investigation (DOI). The first drawback might be answered by using LWD to mitigate fluid invasion issues instead of logging a live well. The second drawback is addressed by taking advantage of the newly-developed LWD multiple depths of investigation (MDOI) Σ measurements (shallow Σ, medium Σ, and deep Σ) to determine the presence of invasion. If invasion has occurred, via a new MDOI inversion process analogous to the resistivity step-profile inversion, we estimate both invaded and virgin zone Σ for use in petrophysical applications.

We analyzed LWD MDOI resistivity and sigma logs acquired in an oil-producing reservoir drilled with a low-invasion water-based mud for a remaining Oil Saturation (ROS) study. The coring operation has allowed some invasion to take place, which can clearly be seen from the separation of MDOI sigma curves. The inverted (true) Sigma allows meaningful Sw comparisons between LWD, wireline and core analysis. The errors on estimating water saturation and salinity using shallow Σ, medium Σ, deep Σ, and true Σ are illustrated to highlight the need to correct for invasion before doing quantitative formation analysis with Σ. The results indicate the viability of using LWD measurements to determine ROS in flooded reservoirs with mixed/unknown salinities.
Success & Scope of Infinite Conductivity Fracturing Channels in Cambay Basin of India
Authors: Barasia A. , Ramanathan V. , Christiawan A. , Srivastava A. K , Sharma Vivek , Mishra D. C. , Biswas S. K.
Published: November 2012

Cambay is one of the oldest basins in India producing hydrocarbons since 1960's. It stretches almost 400 kilometers from south of Rajasthan to south of Gujarat in the western part of India and covering 53,000 sq. Km of total area. Cambay basin is contributing almost one-third of India's total onshore oil production. Raising production from Cambay basin is a considerable challenge as major producing fields are all Brownfield's.

Hydraulic Fracturing (HF) is in use since 1980's to stimulate and enhance production from average to poor quality sands of Cambay basin. HF leads to better production results and has helped in enhancing production from this region for a long time. HF success ratio in stimulating these reservoirs dwindled significantly in the last decade due to continuous exploitation and decrease in saturation and reservoir pressures in the area. Enhancing fracture effectiveness & conductivity and reducing pressure drop within fracture was key to overcome this challenge and take the production to the next level.

Maximizing conductivity of proppant pack has its own inherent limitations and this led to the application of channel fracturing for the first time in India in the Cambay basin. Channel fracturing results in decoupling fracture conductivity from proppant pack conductivity and results in infinite fracture conductivity, longer effective fracture half-lengths & reduction in pressure drop in the fracture. Creating stable fracture channels is highly dependent on rock mechanical properties and first hand evaluation of this decides applicability of this technology in a particular field/sand.

This paper discusses the production results of wells treated with open channel fracturing compared to production results of offset wells stimulated by Conventional fracturing technology. Then it sheds light on basic requirement and key factors to be able to decide applicability of this technology in a particular field/sand. In the end applicability of this novel technology in all the major fields of Cambay basin will be discussed with the overall scope of redevelopment of all the major brown-fields of India.
Wellhead Platform Extension Project - Solution for Additional New Well Slot on an Existing Wellhead Platform
Authors: Irawan Chandra , Husen Wahyu Prawira
Published: November 2012

Offshore wellhead platform (OWP) extension is one of Total E&P Indonesie (TEPI) strategic action to slowdown the natural decline of total production by giving possibility to add new well-slot on an existing wellhead platform that its well-slots have been all occupied.

Wellhead platform extension project scope is to extend the existing platform structure in order to accommodate additional three or four new well slots. New well slots will be equipped with Conductor Pipe (CP) Guide above and under water, and also CP Protection Frame. Additional Wellhead Control Panel (WHCP), field instruments, F&G system and electric power supply are also constructed for the new wells. Modification of control system is also required in order to integrate new wells input/ output points and Safety Shutdown System (SSS) to the existing Distributed Control System (DCS) for process control.

As brown field project, OWP project activities are executed in SIMOPS (Simultaneous Operation) condition with production activities. Field Operation team as a host will ensure the project will be done safely within their operation perimeter and with minimum impact to production continuity especially due to unplanned shutdown. Field Operation also responsible to prepare procedure and line-up the system for tie-in between new and existing facilities (i.e. piping and instrument). Generally there will be requirement for platform shutdown period in order to perform final tie-in, commissioning, and final start-up of new facilities.

Offshore wellhead platform extension project include several high risk activities such as: saturation diving, heavy lifting and naked flame jobs within existing live facilities, which become project major challenges and require detailed job risk assessment and good preparation from both Project and Field Operation team. Currently, offshore wellhead platform extension has been successfully implemented on seven TEPI's platforms within three years and with minimum impact to production continuation.
Using CFD to Model the Performance of Retrofit Production Separators in Abu Dhabi
Authors: Kharoua Nabil , Khezzar Lyes , Saadawi Hisham
Published: November 2012

An earlier SPE paper described a Computational Fluid Dynamics (CFD) study to model the performance of the three-phase separators in an onshore oil field in Abu Dhabi The aim of the study was to develop better understanding of the multiphase flow in the separators and to compare its performance before and after upgrading of the internals. A combination of the Eulerian-Eulerian multiphase and k-ε turbulence models was used to simulate the complex internal flow behavior.

This paper is a continuation of the previous work. It describes the internal flow behavior and analyses the impact of the various internal components on the flow pattern.
Rock Mechanical Facies; Classification and Use in Carbonate Reservoirs, Offshore Abu Dhabi
Authors: Williams Math P. , Edwards H. Ewart , Bratli Rolf K.
Published: November 2012

Rock mechanics tests on core from Early Cretaceous carbonate reservoirs from a super-giant field offshore Abu Dhabi has allowed definition of rock mechanical facies (RMF). Each of four RMF are based on stress-strain curves and associated strength and elastic parameters. The lab-based RMF correlate with mechanical stratigraphy classes previously defined from core (and that reflect visible differences in lithology and cementation). The RMF are correlated to reservoir zones and inter-reservoir, impermeable dense intervals, with three facies predominantly correlating with reservoir lithologies and one corresponding with primarily dense intervals. However, some reservoir zones, or sub-zones, can lie in more than one RMF. The RMF are, therefore, partly predictable: for any reservoir zone in the field prediction accuracy is to one or one of two RMF classes. This ambiguity is due to two factors: (i) lateral variation of RMF within some reservoir zones based on lithofacies; and (ii) continuity of mechanical properties between RMF classes. There is a change in RMF from crest to flank of the reservoir, as expected, but there is also local lateral variation within the crest of the field. The two RMF representing most of the reservoirs are expected to respond differently to field operations. Therefore, mapping lateral variation of RMF for some reservoir zones may provide a basis for implementing different reservoir management practices in different areas/zones of the field. The ultimate use of this information will be to enable full-field rock mechanics simulation of the reservoir to help understand the long-term effects of different production strategies.
Completion and Stimulation Methodology for Long Horizontal Wells in Lower Permeability Carbonate Reservoirs
Authors: Jackson Alfred , Al Azizi Badr Musabbeh , Kofoed Curtis , Shuchart Chris , Keller Stu , Sau Rajes , Grubert Marcel , Phi Mike
Published: November 2012

In this paper, a new carbonate stimulation methodology and its impact to the planning of very long, open hole completions will be presented. While the key objective of stimulation is to connect the well to the reservoir, completion equipment design and related well performance have become more important factors. Traditional methods of stimulation modeling and fluid placement are no longer sufficient for these types of wells.

This paper introduces how completion design becomes more complex for more aggressive stimulations. For example, completions with pre-drilled or slotted liners for stimulation with coil tubing acid wash are less sophisticated than ball drop liners for high-volume acidizing or fracturing. In long horizontal completions, computer modeling of stimulation needs to address the flow conditions caused by liners, swell packers and inflow control devices (ICDs). Recent well planning for a long horizontal pilot well (Pilot Well 5) has included the use of new carbonate matrix stimulation software to design a fit-for-purpose completion liner that will accommodate bullhead treatment of a long completion interval. Various completion designs were considered based on objectives from reservoir engineering and geology. Being part of a pilot well program, the strategy is to test fit-for-purpose liners that would balance completion cost with long term productivity and recovery.

The well design required more than 100 runs of the new carbonate matrix acidization software to finalize a liner design that employs over 200 holes distributed along the length of the lateral. The final design was developed to accommodate uncertainties in the reservoir properties and allow for safe and reliable rig operations. The resulting design could serve as a lower-cost alternative to ball drop stimulation liners for long openhole completions.
Drilling Multi-Lateral Infill Wells for Incrementing Oil Production. A Case Study from a Mature Field
Authors: Zuckmeyer E. , Mathadil A. , Gunasan E.
Published: November 2012

The offhsore oil field, situated offshore Abu Dhabi, has been operated by TOTAL for nearly 40 years. At the time of development it was estimated that recovery of the original oil in place would be recovered and that the field would be abandoned shortly. Since the early 1970s, however, many new innovative technical solutions have been employed to improve recovery and maintain economic production; one such technology has been the progressively complex multi-lateral wells that have been successfully used to drain smaller and smaller pockets of residual oil. As a consequence, recovery today is high and with certain reservoir layers reaching a record recovery factors in a carbonate reservoir.

The Upper reservoir, concerned by the advanced drilling technology, is composed of alternate layers of anhydrite and dolomite. The numerous horizontal barriers created by the anhydritic beds have led to the presence of 5 different oil-water contacts and variable, but generally poor, natural aquifer pressure support. In addition, the pressures and oil API were different and caused independent dynamic response to the production. The intermittent tight, intermediate and permeable layers also further complicated the development. Due to all these difficulties, the recovery factor is less compared to other reservoirs in the field.

Initially the production from the reservoir was with vertical wells but then deviated wells began to be drilled from the fixed platforms. The pressure support was provided by peripheral water injectors. The deviated wells were useful in targeting remote areas of the reservoir but, since the layers were thin, the exposure to the reservoir was limited. Also, this resulted in the permeable layers being more developed than the tight layers due to the commingled production.

To improve the oil recovery, an innovative technology was applied for the first time in 1997. TOTAL introduced the drilling of multi-horizontal drains. The completions were innovative allowing for gas lift and selective, independent production of each drain as necessary. Depending on the physical properties of the targeted layer, the proximity of nearby wells and drilling feasibility, the drain lengths ranges from 300m to 1000 m.

Since 1997, over 30 Multi-lateral wells have been drilled with up to 6 branches per well and targeting layers as thin as 1.5m. Many wells have used up "dead" slots, thus adding incremental reserves with limited impact on existing facilities. After 14 years of experience drilling such wells, this paper provides a Case Study highlighting the production benefits as well as a review of some of the technologies that were introduced to achieve them.
Novel Design and Implementation of Kuwait's First Smart Multilateral Well with Inflow Control Device and Inflow Control Valve for Life-cycle Reservoir Management in High Mobility Reservoir, West Kuwait
Authors: Das Om Prakash , Al-Enezi Khalaf , Aslam Muhammad , El-Gezeeri Taher , Ziyab Khalid , Fipke Steven R. , Ewens Steven
Published: November 2012

Increased hydrocarbon recovery and accelerated production from ultra-high water mobility oil-wet reservoir requires the application of advanced well completion technologies to address premature water breakthrough, reservoir management, production management and extended reservoir contact from a single well location. The Burgan Reservoir of Minagish Field, West Kuwait has active aquifer, very high permeability sands associated with active faults and contain highly viscous reservoir fluid with downhole viscosity of 40cp, enhances water mobility and resulted in premature water breakthrough with increasing water cut trend within few months of production as confirmed from well performance of existing horizontal wells. This has resulted in to non-uniform reservoir depletion, by-passed oil regions and low oil recovery.

The Kuwait's first smart level-4 multilateral well was completed in Burgan reservoir by combining the Level-4 junction along with stacked dual lateral completion having customized viscosity independent Inflow Control Device (ICD), customized two Inflow-Control Valves as well as down hole gauges, wide operating range Electrical Submersible Pump (ESP), suitable wellheads, X-MAS tree and Integrated surface panel for real time data monitoring.

The smart multilateral well has assisted in addressing premature water breakthrough, enhanced dry oil production and facilitated uniform depletion, which results in improved hydrocarbon recovery. The paper covers the customized design of smart Level-4 multilateral well by taking in to account the reservoir and its fluid characterization, well architecture, implementation and specially designed invert emulsion drilling fluid for effective wellbore cleanup to achieve formation virginity. The improved reservoir management and production management results are also mentioned in this paper.
From 360 Deg Health Safety Environment Initiatives on the Rig Site to Structured HSE Strategy: A Field Case in Abu Al Bukhoosh Field
Authors: Cuvex-Micholin Marc , Baccino Bernard , Essel Philippe
Published: November 2012

TOTAL Abu Al Bukhoosh (TABK) has irritated a well sequence with the Perro Negro 2 rig (PN2); a Jackup MODU. The rig contract started early January 2010 and may be extended till end of 2015, based on HSE and technical performances.

Since day one, it has been decided to boost the HSE performance with robust Management Leadership, Engineering HSE and ergonomics, and working on the Employees behavior. This well known drilling industry approach has been augmented by TABK decision to surpass general standards. Two additional Safety Officers providing 24 hours HSE coverage were hired by the Rig Contractor. One Rig Site Safety Advisor was mobilized by TABK. Their constant presence provides a close working relationship with the front line workers and Team Leaders. Several audits and ‘’360 Deg’’ HSE initiatives were able to increase the HSE awareness of all.

PN2 has no recordable incident since 900 days. Initially, the HSE initiative and audit plans were based on the experience of the Managers offshore and onshore and not really linked to a formal ranking of the risks.

New sophisticated tools are being developed in the Oil & Gas Industry to rank risks: For example, TABK HSE and Asset Integrity Departments are working on Technological Risk Assessment and Threat Registers. Multi-yearly mitigation measures and action plans are proposed. The well recognized ‘’likelihood-consequences’’ matrix has been adopted also for rig operations. It allows for highlighting the risks per area and the main population involved, ranks the areas per overall risk, and thus develops an audit/frequency plan related to those risks.

With such structured and formalized HSE strategy, risks are well captured, type and frequency of the audits are straight forward, and barriers are implemented for a residual risk ALARP.

This paper will explain in greater detail how this was achieved, the challenges that were encountered during the implementation of the tool, and how the Team intends to continue to add value in such a new HSE culture orientation.
Air Emission Reduction & Zero Flaring & Venting
Authors: Mian Mahboob , Al Qubaisi Nawal
Published: November 2012

Gas Processing Facility (GPF) project achieved Zero flaring

1.7million standard cubic feet per day (41.65 tons) gas recovered thru Vapor Recovery System and protect the environment by reducing;

CO2: 3,924 tons/yr

CO: 123.6 tons/yr

NOx: 21.6 tons/yrs

➢ Total gas recovered: 612 million standard cubic feet per year ➢ Revenue saving: 835,380 US$ /year

Vapor Recovery Unit (VRU):

Under this unit, gases from the Tertiary Ethyl Glycol (TEG)Dehydration package and vents from compressors dry gas seals are recovered/ captured and compressed in the VRU and then sent to the suction for the main gas compressor for reuse instead of going to flare

Gas Processing Project (GPF) at Zakum complex is a new gas treatment platform that will augment the existing gas processing capacity of the Zakum West Super Complex. It will increase the associated gas production from Zakum oilfield. The beauty of this project is that ADMA has employed the Zero flaring policy. There will be no flaring at all at this platform. This is one of the unique project of its nature in the ADNOC group of companies, even in Emirates and could be in the whole middle east where is there would be NO flaring. We have designed flare as well in this project but that would be used only for emergencies.

GPF is a stand alone platform with independent utilities and support facilities. The GPF platform is 67.5 meter in length and 43 meters in width. GPF is located at Zakum oilfield, offshore facility about 65 kilometer Northwest of Abu Dhabi. This platform has three main decks, cellar, mezzanine and main. The flare structure consists of a 120 meter long flare bridge with a 80m above sea level angled boom. The distance from the flare tip to the GPF platform is 150 m. There will not be any flaring during normal operation of the GPF, as Zero flaring technology is installed. Hydrocarbon from the GPF platform will be recovered using a Vapour Recovery Unit (VRU) facility. Flaring will only be undertaken during emergency conditions.
Modeling of a New Single-Well EOR Piloting Technique: Application to CO2 EOR
Authors: Kristensen Morten , Ayan Cosan , Ramamoorthy Raghu
Published: November 2012

Screening and piloting of enhanced oil recovery (EOR) methods is often a lengthy process requiring large financial commitments. The reservoir uncertainty and, for some EOR methods, the lack of fundamental recovery mechanism understanding, call for a careful and staged screening and piloting program before committing to full-field implementation. The MicroPilot* single-well in situ EOR evaluation is a new piloting technique which allows for rapid and cost effective testing of EOR methods under in-situ downhole conditions. It is a log-inject-log technique conducted with a wireline formation tester, where a small quantity of EOR fluid is injected and the resulting change in oil saturation then determined based on a set of openhole logs that are run both before and after the injection.

The MicroPilot is a proven piloting technology for alkaline-surfactant-polymer (ASP) EOR. In this paper, we investigate the feasibility of extending this new technology for testing of CO2 EOR. We demonstrate through detailed analytical and numerical modeling that the changes in oil saturation and composition expected during the CO2 EOR process are measurable by the openhole logs when taking into account logging tool resolution. Based on a test library consisting of 13 different oils, which have been carefully characterized to match experimental PVT data, and all of which are likely candidate oils for miscible CO2 EOR, we investigate the expected pilot response when injecting CO2 both above and below the minimum miscibility pressure. We further study the sensitivity of the pilot response to gravity effects as well as residual oil saturation to the CO2 flood.
Derivation of Immobile and Non-vaporizing Residual Oil Saturation under Miscible Flood from CO2 Coreflood Experiments
Authors: lizuka Ryo , Al-Shehhi Hamad Rashed , Al-Hammadi Hamdan Mohamed
Published: November 2012

It is important to predict the amount of bypassed oil in EOR gasflooding since some portion of the flooded domain may be uncontacted by the injected gas due to reservoir heterogeneities residing in various scales. In this paper, we present a new method of deriving immobile and non-vaporizing residual oil saturation under miscible flood (Sorm, Hiraiwa and Suzuki 2007) from the results of CO2 coreflood experiments. We also demonstrate that Sorm is a sort of upscaled parameters able to absorb complex heterogeneous features in the finer scale.

We history-matched CO2 coreflood experiments using the two different simulation models: one-dimensional (1D) homogeneous model with Sorm and two-dimensional (2D) heterogeneous model without Sorm. Both of these two models replicated secondary- and tertiary-mode CO2 coreflood experiments using core and fluid samples acquired in one of the Abu Dhabi's offshore fields. Hence we successfully obtained the Sorm based on the coreflood experiments for further use in evaluating CO2 injection in a real reservoir. In addition, we effectively modeled the core-scale heterogeneity using the X-ray computerized tomography (CT) data and pore size distribution (PSD) data derived from mercury injection capillary pressure (MICP) tests in the 2D model.
Development of Flank Areas in a Giant Carbonate Field with Optimal Well Placement of Horizontal Wells
Authors: Khan Sameer , Al-Shabeeb Ali , Jani Zankar , Azoug Yousef , Minh Nguyen , Patel Harshad
Published: November 2012

Flank areas pose a particular field development challenge in giant fields with low dip where the transition zone is spread over a large area. Successful development of flank areas depends on accurate reservoir characterization, in particular, water saturation distribution in addition to the optimal placement of wells, both areally and vertically. In relatively thin reservoirs, horizontal wells are generally preferred to increase reservoir contact using lower well counts. Proper spacing and vertical placement of horizontal wells are, however, critical. Well spacing is closely linked to oil recovery, pressure support, and sweep efficiency. Similarly, placement of horizontal wells in the right layer is vital for maximum vertical sweep. In order to test initial concept in the field, two existing producers were converted into injectors and pressures were monitored at the offset producers. Surveillance showed that the injectors were able to support producers 1 km away. This paper describes the process of arriving at the optimal well placement for maximizing oil recovery in the flank areas. This study is applicable to giant oil fields with large flank areas which pose significant development challenges.
Multi-Phase, Multi-Component Simulation Framework for Advanced Recovery Mechanisms
Authors: Moncorgé Arthur , Patacchini Leonardo , de Loubens Romain
Published: November 2012

Numerical modeling of advanced recovery mechanisms at the reservoir scale (e.g. miscible or immiscible Gas1 flood, chemical flood, steam injection…), typically implemented in a tertiary phase, is essential to reasonably estimate their potential benefit and to rank the various field development options. In this perspective, using a unique advanced-physics simulator for the entire life of an asset is a desirable objective, because in addition to saving engineering time spent in data conversion, it ensures continuity of the models at all times. In our view such a tool, expected to be flexible and allow reactivity for testing new models, should come as a complement to optimized and robust industrial-grade simulators used for prediction and history matching during primary and secondary recovery.

In this paper we present the prototyping framework implemented in our In-House Research Reservoir Simulator (IHRRS), enabling easy integration of new physics for improved recovery processes with the well-known Black-Oil and K-value or Equation of State compositional models. As a demonstration example, we choose Surfactant-Polymer (SP) flooding, possibly requiring an additional Microemulsion phase. The framework is based on a natural variables formulation, solving a coupled system of conservation equations for the hydrocarbon and aqueous components (and optionally for the energy), simultaneously with a set of local thermodynamic constraints. These constraints enforce the equilibrium of hydrocarbon and aqueous components across the different fluid phases, including the equilibrium of Water and Oil with Microemulsion.

To ensure compatibility between the different recovery mechanisms handled by our system, as well as to facilitate their development and benchmarking, special attention has been paid to developing physical options as plug-in functionalities. For this purpose, instead of relying on complex software engineering tools we prefer the approach of using low-level interfaces to communicate between the core and the modules (such as the fluid, the petrophysical, or the surface facility modules). Most of our modules are entirely independent from each other, and can be compiled as stand-alone programs to be called by MATLAB® or Python scripts for instance; symmetrically, they could be replaced by external software in order to test third party functionalities.

As a first benchmark of our IHRRS, we consider a surfactant-polymer flood scenario in a 2D anisotropic quarter five-spot setting, and compare our solutions against those of a reference academic chemical flooding simulator (UTCHEM). The potentialities of our framework will then be demonstrated on a simplified model of a real Middle-Eastern field.
Increasing the Agility of Process Safety Management Systems
Authors: Rains Brian
Published: November 2012

The oil & gas industry is constantly adapting to change, be it related to price, technology or market demand. High prices of crude oil and advances in technology have allowed producers to access resources previously out of reach, and extract maximum value from these resources. With this, however, operational risk is significantly augmented - both upstream and downstream. In order to cope with this increased risk, it is vital that oil & gas companies have a process safety management (PSM) system that fully integrates management of change methodologies.

DuPont has developed a PSM system that fully integrates change management across multiple facilities, among personnel and in light of technological advancement. While these must be considered singularly, it is also important for companies to build a holistic system that accounts for the interdependent nature of operational systems, and thus address process safety from every possible angle - training and skill development to hazard analysis and maintenance. However, as only a limited number of procedures can be universally applied to cope with changing process conditions, this paper will also detail the means through which companies can develop customized solutions for specific conditions and contexts.

By developing a model that can effectively manage change, it is possible for oil & gas companies to not only avoid catastrophic incidents, but also increase the overall safety of an operation, while concurrently maximizing efficiency, cost-effectiveness and quality.

The extraction and processing of oil and gas is a highly technical mechanical operation that involves volatile and corrosive substances in often extreme conditions. As such, it is vital for companies within the oil & gas sector to develop a holistic PSM system that can successfully manage process safety, while remaining agile enough to respond to specific issues, and any changes thereof.
Feasibility Study of Single Well Tracer Test for High Salinity and High Temperature Reservoirs
Authors: Mechergui Aymen , Romero Carolina , Morel Danielle
Published: November 2012

The single well tracer test SWTT is a well established method to measure Residual Oil Saturation (ROS) in-situ. The large radius of investigation makes the SWTT a well suited method to evaluate ROS reliably compared with other techniques such as coring and logging.

The partitioning tracer is chosen depending on three basic parameters: reservoir temperature, reservoir salinity and live oil partitioning behavior. These properties control the extent of the hydrolysis reaction that takes place during the shut-in time period to generate the secondary non-partitioning tracer. At high temperature and high salinity (HT/HS), the partitioning coefficient Kd and hydrolysis reaction rate Kh can be significantly high, therefore risking complete reaction of the partitioning tracer and loss of test results reliability.

This paper presents a simulation study carried out to evaluate the feasibility of performing SWTT at HT/HS and help the selection of tracers at these conditions. Using experimental design, a series of SWTT numerical simulations were performed to assess the impact of high Kd and Kh on ROS measurement and interpretability of tracer profile.

Results indicate that conventional rules used for SWTT design would need to be modified or adapted in order to have an interpretable signal from the test. The paper presents also the impact of modified shut-in time and drift on the quality of test.
Enhanced Assessment of the Distribution of Organic Matter in Unconventional Plays and Tarmat in Reservoirs Using a New Laser Pyrolysis Method on Core
Authors: Dessort D. , Gelin F. , Duclerc D. , Le-Van-Loi R.
Published: November 2012

Estimation of the amount, the distribution and the quality of the sedimentary organic matter (kerogen) in unconventional plays or tarmat in reservoirs are often key to a proper assessment of the viability technique and/or commercial of these plays. Conventional core- or log-based methods for the evaluation of organic carbon content in various types of formation (e.g. tarmat in reservoir, oil shale and gas shales) are not always satisfactory due to limited resolution and/or non-reliable data.

The acquisition of quantitative and high resolution (centimetric or sub-centimetric) logs of organic carbon on core can be performed, at the labs or at the coring site, using a continuous power laser (LIPS: Laser Induced Pyrolysis System). The technology was first developed to identify the presence of tarmat in carbonate reservoirs where the results impacted the assessment of the reservoir quality, the GOIIP, the presence of permeability barriers and the response of electric logs.

More recently it has been successfully applied on various unconventional studies. For instance it was possible to have a high resolution, accurate and quantitative measurement of total organic carbon in oil shale or gas shale plays. It then allowed (i) to estimate the yield of petroleum which can be produced from oil shale Pyrolysis (ii) to extrapolate, model and map the quantity of the remaining petroleum potential of oil shale deeper in the basin.

This technology will greatly benefit the mapping of these unconventional plays by providing, in particular, a very accurate tool to calibrate conventional well logs with respect to the distribution of the organic matter.