bluuebunny/crossref_metadata_2025 huggingface dataset:
Integration of Core and Log Data for Classification of Reservoir Rock Types in Minagish Reservoir of Greater Burgan Field, Kuwait
Authors: Hayat L. , Al-Rushaid M. A. , Datta K. , Al Sabea S. H. , Muhammad Y. , Gomez E. , Clark W. , Ma Y. Z. , Bond D. J.
Published: March 2015

A detailed Geological and Petrophysical characterization was achieved in a stepwise approach as part of full field 3D Reservoir Modeling and Simulation study for Minagish reservoir in the Greater Burgan field in Kuwait.

Foundation of Reservoir Rock Types (RRT) was developed in first step based on Mercury Injection Capillary Pressure (MICP) dataset. A combination of Discriminant Analysis and Indexed Self Organizing Map (SOM) was used for rock type classification using hyperbolic tangent method. To improve classification of bimodal Pc curves, additional pressure values at different non-wetting phase saturations were used in conjunction with above mentioned parameters. In second step, the available Routine Core Analysis (RCA) porosity, permeability data was grouped together based on common patterns to generate rock types in RCA domain. Blind tests in two of the cored wells revealed a conformance of 81% between MICP and RCA Petrophysical Groups (PG). In the final step of the process, petrophysical groups were propagated in log domain using available log measurements common in all the wells of the field. It was challenging to establish a high level of accuracy for PG's in log domain mainly due to fine scale heterogeneity and inability of log data to capture rock fabric variation.

This porosity estimate, coupled with rock type classification, helped to derive a continuous permeability log with a correlation coefficient of 0.89 validated in key cored wells. The porosity and permeability data in all the wells was incorporated in the 3D geocellular model after up-scaling honoring the unique, per rock type, Phi-K relationship.

Modeled capillary pressure curves generated for each rock type in the core domain using MICP data set in 3 wells were used in saturation height modeling. The modeled equation was captured in the 3D geocellular model after populating rock types in the 3D grid to map water saturation for volumetric estimation.

Introduction

A 3-D static model of the Minagish Reservoir, Greater Burgan Field was constructed that integrated the available geological, geophysical, petrophysical and engineering data. This model was populated with facies, petrophysical properties (porosity, permeability and water saturation) and reservoir rock types. The paper demonstrates the significance of rock type classification within an integrated reservoir characterization study giving a narrow range of uncertainty and how it can impact prediction of reservoir flow performance.
Development of a Polymer Gel System for Improved Sweep Efficiency and Injection Profile Modification of IOR/EOR Treatments
Authors: Crespo Freddy , Reddy B. R. , Eoff Larry , Lewis Christopher , Pascarella Natalie
Published: March 2015

The existence of high-permeability features, such as fissures, fractures, and eroded-out zones, diminishes the sweep efficiency of any water, gas, or polymer flooding operation. Placing crosslinked conformance polymer gels or other types of blocking agents in injection and/or production wells can generate the necessary flow diversion for increasing the recovery factor of enhanced oil recovery/improved oil recovery (EOR/IOR) treatments.

This paper evaluates a high-molecular-weight (HMW) organically crosslinked polymer (OCP) (referred to as HMW-OCP) gel system for such scenarios. This conformance technology is the result of crosslinking reactions between HMW polyacrylamide and polyethylenimine (PEI). The relatively medium viscosities of the fluids caused by the HMW of the components of the system allows for in-depth gel placement in fractures and high-perm channels, without invading the matrix of the rock. A low-molecular version of this polymer system has proven to successfully control water production in matrix applications.

This HMW-OCP system gelation occurs gradually with time and temperature and can be designed to suit the need for short and long placement times. Optimization of gelation times using chemical activators and bimodal distribution of polymer molecular weights (MWs) is discussed. Fast hydration of the base polymer provides on-the-fly mixing capabilities. Also, the use of all liquid polymers and additives allows ease of transportation, handling, and storage and mixing of large volumes of material usually necessary for this type of treatment. Laboratory test results show long-term plugging capabilities, thermal stability, and fluid-loss control.

Introduction

Inadequate profile injection and sweep efficiency are key challenges when trying to achieve reasonable recovery factors with IOR/EOR treatments. Fractures, high-permeability channels, and other heterogeneities present in reservoirs are very likely to provide preferential paths of least resistance to the fluid being injected to sweep hydrocarbons causing premature injected-fluid breakthrough. A common way to mitigate this problem and to maximize the amounts of swept oil from the reservoir is to place sealants or blocking agents in such flow paths. Polymer gels and other types of conformance materials are permeability-reducing agents that can fill fractures and high-permeability channels at the injector or producing well to generate flow diversion and increase sweep efficiency.

There are several technologies that can be used to reduce injected-fluid production and increase sweep efficiency in fractured reservoirs.Crosslinked polymer gels.In situ swellable particulate polymers (or preformed gel particles).Triggered in situ activation of nano-sized gel particle emulsions.Silicate systems.
Shale-Fluid Interactions and Drilling Fluid Designs
Authors: He Wenwu , Gomez Sandra L. , Leonard Russell S. , Li David T.
Published: March 2015

Advanced directional drilling technology has made it possible to drill extended reach wells with long horizontal displacements, resulting in optimally placed wellbores within reservoirs and more economical hydrocarbon production. Logging-while-drilling (LWD) technologies provide new opportunities to improve reservoir characterization and geologic models however, the complicated wellbore and formation geometries in highly deviated wells impose difficulties for quantitative interpretation of well logs using conventional petrophysical analysis methods. LWD log interpretation in high-angle and horizontal wells is often limited to geosteering in well placement applications and qualitative reservoir description.

We developed a state-of-the-art formation evaluation toolkit for quantitative interpretation of well logs in high-angle and horizontal (HA/HZ) wells. Starting with wellbore images and standard triple-combo field logs, the workflow consists of: 3D and 2D displays for well path, wellbore images and field logs to quality control the data;comprehensive image and log analysis to build a 3D geometrical earth model;depth coherence analysis to effectively correct the recorded wellbore images of various logging tool sensors with different depths of investigation;3D joint inversion to accurately model and interpret gamma-ray, neutron, density and resistivity logs in order to build a common petrophysical earth model; andpopulating the common earth model with bedding geometries and rock- and fluid-property distributions.

The toolkit has been successfully applied to a field example to illustrate its applications in quantitative reservoir characterization of net-to-gross (N/G), porosity (???), and water saturation (Sw). Incorporating more accurate descriptions of bedding dips and azimuths from HA/HZ wells within the earth model results in improved geologic models for reservoir simulation. Sensitivity analysis in the workflow defines the uncertainties in wellbore image analysis and wellbore directional surveys.

Additional uplift in reservoir characterization includes quantifying lateral variations and improving reservoir facies classifications, along with delineating potential calcite zones and quantifying stratigraphic bedding and orientation. The results include bed thickness distributions and guidance to appropriate petrophysical cutoff values.
Sequence Stratigraphy Framework of late Early to Middle Cenomanian Rumaila and Late Cenomanian to earliest Turonian Mishrif Formations, Onshore Kuwait
Authors: Youssef Abulkader H. , Kadar Adi P. , Karam Khalaf A..
Published: March 2015

A high resolution biostratigraphic and paleoenvironmental investigations were integrated with sedimentology and wireline-log-data to establish a sequence stratigraphic framework of Rumaila/Mishrif section, Kuwait. The biostratigraphic analysis of over 500 core/chips from 9 wells recognized six 4th order sequences over the study section. All the identified sequences correlated regionally.

Three 4th order sequences were identified within the Rumaila Formation: RU100, RU200, and RU300. The RU100-SB lies on the boundary between the non-calcareous restricted shale of the upper Ahmadi Formation and the highly fossiliferous, calcareous marine shale at base of Rumaila Formation. The RU100 and RU200 sequences are represented by marine calcareous shale or marl containing common nannofossils and marine microfossils at their MFSs. The RU300-SB lies on top of the shallower facies, poorly fossiliferous highstand of the under-laying sequence. The RU300-MFS is indicated by abundant micro/nannofossils. This marine event is equated with the regionally known K130.

The Rumaila/Mishrif contact is placed at the shift in facies from the deeper water facies of Rumaila to a shallower facies of Mishrif. The shallower facies of Mishrif is bioclastic wack/packstone enriched upward in rudistid and coralline fragments forming a fair/good quality reservoir.

Three 4th order sequences were identified within the Mishrif Formation: MISH100, MISH200 and MISH300. The MISH100-SB lies on top of recrystallized wack/mudstone and packstone ending up with a dolomitic wackstone. The MISH100-MFS is indicated by planktonic foraminifers. MISH200-SB lies on top of Praealveolinid wack/packstone of the previous sequence. MISH200-MFS is indicated by planktonic and benthonic foraminifers. The MISH300-SB lies on top of the Praealveolinid wack/packstone ending up with lagoonal non-calcareous shale. The MISH300-MFS is indicated by planktonic and benthonic foraminifers. This marine event could be equated with the regionally known K140.

The Rumaila is considered as a good seal all over Kuwait while the Mishrif is considered as a fair/good quality reservoir towards the south. Micritic matrix, moldic, vuggy and fracture porosity reservoir is represented in parts of MISH100, MISH200 and MISH300, while the rudist, coralline floatstone reservoir is existing within MISH300-HST of some areas. Geologic model is presented to show; depositional setting, paleoenvironments, basin configuration and geographic extension of different sequences.

INTRODUCTION

The focus of this study is on the Rumaila and Mishrif section which occupies the upper part of Middle Cretaceous Wasia Group, which is composed of Burgan, Mauddud, Wara, Ahmadi, Rumaila and Mishrif formations. The group was formed during the latest Aptian, Albian, Cenomanian to earliest Turonian (111 Ma - 92 Ma), and was deposited in about 19 m.y.
Waterflood Optimization and its impact using Intelligent Digital Oil Field (iDOF) Smart Workflow Processes: A Pilot Study in Sabriyah Mauddud, North Kuwait
Authors: Khan Mohd. Yunus , Chetri H. , Saputelli L. , Singh S.
Published: March 2015

The Sabriyah Mauddud (SAMA) limestone reservoir of North Kuwait is a large oil reservoir currently under waterflooding to meet production targets, and optimization of water injection is critical. The engineers have begun monitoring, diagnosing, and optimizing this waterflood through the implementation of an intelligent digital oil field (iDOF) program called KwIDF (Kuwait Integrated Digital Field). Various workflows have been developed for the visualization and analysis of waterflooding performance. Such workflows use real-time production data to derive and update daily water saturation and reservoir pressure from numerical simulation. The ultimate goal of this workflow is to identify and define actions to improve water injection and production over the short and medium terms. The transformation of raw data into information is achieved through intelligent, automated work processes, which are referred to in this paper as "smart workflows." These smart workflows assist engineers with daily well surveillance activities, aid productivity, and help improve the speed and quality of their decision-making process. The workflow presented is related to waterflood management; however, it is part of a family of smart workflows (e.g., electrical submersible pump [ESP], subsurface waterflood optimization [SWFO], and smart production surveillance [SPS] workflows), which have been discussed in other work. These smart workflows and a commercial software, Oil Field Manager (OFM) for Decline Curve Analysis (DCA), have also been used in waterflood optimization for the optimum production allowable selection, with the ultimate goal of improving asset performance.

This paper shares how these smart workflows are used for waterflood optimization and illustrates a case study of an injection pattern optimization and its impact on production. Comprehensive monitoring of the waterflood has been performed using real-time data through iDOF smart workflow processes, illustrating the analysis of real-time data, which includes pump intake pressure, flowline pressure, water cut (WC), and flowing bottomhole pressures. Other data used include static bottomhole pressure, production log results, and production flow tests. Monitoring is planned in such a way to understand waterflood movement within the reservoir from injector to producers and its impact on the production behavior of the surrounding producers. A positive response in terms of pressure maintenance and production increase has been observed and confirmed using various analytical tools.
Produced Water Management For Sustainable Reinjection - Bench Scale Tests To Remove And Destroy KHI
Authors: Al-Shaabi Mohammed , Emadaddhi Khalid , Roquet Damien
Published: March 2015

Dolphin Energy Limited's (DEL) production scheme is based on a wet transport of well effluents from offshore platforms (DOL-1 and DOL-2) to the onshore treatment plant. At the onshore receiving facilities, sour gas is routed to gas sweetening, condensate is stabilized and treated and produced sour water is routed to water treatment units.

Since the plant startup in 2006, non-chemically contaminated waste water is used for irrigation after treatment. Produced waste water and chemically contaminated waste water are re-injected into a deep reservoir without any major treatment further to H2S stripping, oil skimming, pH control and multi-media filtration. However, local authorities have expressed their concerns about the quality of water injected and the potential risk of long term injectivity loss.

Indeed, as sealines need to be protected all year round against corrosion using a Corrosion Inhibitor (CI) and hydrate formation during winter by using Kinetic Hydrate Inhibitor (KHI), produced water recovered onshore is chemically contaminated with polymer based chemicals.

As KHI could damage the reservoir, it has to be removed from produced water prior to reinjection. However, no technology was clearly available and referenced for this application. Dolphin Energy launched numerous bench scale tests with a third party laboratory to identify the best treatment scheme to remove KHI.

The paper will first explain the overall strategy put in place to identify applicable processes. Then, it will describe the laboratory tests on produced water for KHI removal and destruction. Eventually, results will be presented and compared in order to conclude with applicable treatment schemes that would remove and destroy KHI from produced water for sustainable reinjection.
Geared Centrifugal Pump (GCP) Technology Implementation in Petroleum Development Oman, as a potential Alternative Artificial Lift Method - Oil Wells
Authors: Al-Bimani A.  S. , AbdulElraouf A.  I. , Al-Salmi A. , Al-Hinai Z. , Morrow W. B. , Al-Masfry R.
Published: March 2015

The Company's 5-Year Business Plan shows that well operating cost (OPEX) is increasing, especially for mature fields. It is anticipated that some mature fields will not be economic to operate if these cost continue to rise. The lift and well servicing costs are key components of the well OPEX budget. Given that 90% of the company's well stock is completed with artificial lift system, new lift technologies with potential savings are needed.

The operating companies have always been looking for alternative lift method to lift high volume wells at lower cost. The Geared Centrifugal Pump (GCP) is a new high volume artificial lift system that combines the rod string drive of a progressive cavity pump with a multi-stage centrifugal pump of an ESP, via a down-hole speed increasing transmission. It is anticipated that this new system will reduce costs associated with well intervention as failures related to the drive string can be executed by smaller well service units. In addition, electrical and drivehead mechanical failures can be rectified at surface at less cost. Moreover, the GCP pump is cost effective equipment as it eliminates the expensive motor, cable and surface controller. In this notion the GCP pump will address both the lift and servicing cost challenges when compared to other lift systems.

PDO expects to complete all six pilot GCP installations in two of the north Oman fields before performance of the GCP system compared to the widely used ESPs in the same field. At the end of end-2nd qtr. 2013. The objectives of this pilot trial are to test the efficiency, reliability and operational the approx. one-year trial period, the technical and commercial values will be quantified and thus confirm the viability of deploying the lift system further.

This paper will discuss trial objectives, deployment experience, real time monitoring, troubleshooting & optimization. The paper will also highlight the technology challenges; lessons learned and improvements including future deployment plans for PDO.

Introduction

Petroleum Development Company of Oman (PDO), like most operating companies in the world, is experiencing ever-increasing producing watercuts and every increasing operating costs. Since over 90% of PDO oil wells are on artificial lift, the operating companies are constantly looking for innovative ways to improve upon the lift efficiency and maintenance costs, particularly for the high lift volume and high cost ESP equipped wells.

The geared centrifugal pump, or GCP, was seen by PDO to offer an alternative high volume lift system that had the potential of reducing well operating costs by increasing overall lift efficiency and decreasing well intervention costs.
Advanced Technologies For Produced Water Treatment And Reuse
Authors: Hussain A. , Minier-Matar J. , Janson A. , Gharfeh S. , Adham S.
Published: March 2015

Produced Water (PW) is the highest volume liquid waste stream generated by the petroleum industry. Historically, the treatment of PW has been limited to free oil and suspended solids removal, using physical separation technologies, and injection in disposal wells.

However, because of new regulations combined with geological restrictions and local water scarcity, the drive to have a greater fraction of the PW more extensively treated and ultimately reused is increasing. Moreover, the growth in the application of water intensive processes to extract unconventional oil&gas resources, in particular in shale plays and oil sands, has increased the need for cost-effective treatment and reuse of PW to reduce fresh water uptakes.

Therefore, the petroleum industry is investigating new PW treatment technologies given that the physical separation technologies traditionally used in the past are, in most cases, not capable of producing water of suitable quality to replace fresh water uptakes.

This paper presents the results of a laboratory investigation carried out by the ConocoPhillips Global Water Sustainability Center (GWSC), where various treatment processes (membrane processes, membrane-bioreactors (MBRs), membrane distillation (MD) and ozonation) were evaluated as treatment methods for PW from different oil&gas fields.

The key conclusions of this paper are:Membrane Processes and Thermal Evaporators are currently operating within the petroleum industry in full scale PW treatment and reuse applications.The preliminary results of investigations performed by GWSC confirmed the potential of Membrane Filtration, MBRs and Ozonation to treat PW and produce an effluent suitable for reuse. Membrane Distillation may have potential in the longer term. Further investigation is ongoing.If successfully implemented, the above technologies will contribute to provide the petroleum industry with a broad range of technologies to cost-effectively treat and reuse PW.
Effective Wells Corrosion Mitigation in Two Major Middle East Fields: A Case Study
Authors: Alzahrani Mohammed S. , Senusi Kamel X. , Lewis David R. , Al Aty Adel Y. , Shinaiber Fahad A.
Published: March 2015

The focus of most waterflood or pressure maintenance projects is on the performance of the production and injection systems to ensure maximizing field rates and efficiencies. Yet there is a third leg to this operational triangle: the water supply system including wells and gathering system. This paper presents a case study of operational strategies and programs developed from experience from mature Field "B," and then translated to a revitalized re-started Field "F." These strategies include the use of tubeless completions of the water supply wells to maximize the water production rate and the subsequent implementation of a "build-down" strategy consisting of the installation of smaller casing sizes to isolate impaired casing sections and well monitoring with corrosion logs to address casing integrity issues.

Over time, the casing profiles became smaller, the rate of casing integrity issues accelerated and the overall supply well rates could not meet the increased injection demand. These casing integrity issues (up to 60% metal loss in some wells) necessitated a shift in strategy from the mechanical "build-down" to a mitigation strategy to extend the life of the existing supply wells. The "build-down" strategy was effective from 1975 to approximately 2006 in isolating casing integrity issues. The initial chemical squeeze inhibition campaign completed from 1979 to 1981 floundered on the monthly treatment requirements and the attendant high cost for these treatments. As casing profiles become smaller over time, a revamped corrosion inhibitor treatment program was completed quarterly and has been found to extend the well service life by 7 years so far. Furthermore, this case study will review the efficiency of the use of the same corrosion mitigation squeeze strategy in the revitalized Field "F."

Introduction to the Water Supply System of Field "B"

General Background

The mature Field "B" has been in service since 1967 with a peripheral waterflood operation for pressure maintenance since 1972 into the two primary oil producing zones. Waterflood operations are supported by the use of water supply wells completed in a regional water aquifer, sandstone characterized by very high deliverability, with rates of up to 70,000 barrels of water per day (BWPD). This supply water flows to the surface supported by the formation pressure with surface flowing wellhead pressures (WHPs) of between 100 to 125 psig. Initial injection requirements were in the order of 250,000 BWPD in 1983 and have expanded to approximately 363,000 BWPD as of July 2013. At injection startup, there were 21 supply wells, and at July 2013 there are 18 active supply wells. Supply water is gathered from the wells through two flanks to the main operational facilities where the water is pumped into the various water injection wells. It should be noted that these main operational facilities are located within 1500 meters of the Arabian Gulf.
Development and Testing of Advanced Wireline Conveyance Technology for Rugose Open Hole Conditions
Authors: Ahmad Zamri A.  F. , Myers C. H. , Abdelzaher O. , El-Ghammal M. , Ahmed S. , Remmert S.
Published: March 2015

A newly developed style of bottom nose assembly for wireline logging tools is capable of maintaining logging string momentum as the toolstring traverses highly rugose sections of the wellbore. This can reduce or eliminate the need for other conveyance technologies in deviated wells and aid successful descent in horizontal wells.

Although current technology has addressed a significant portion of the market, conveyance in rugose open hole still presents a significant challenge. Drillpipe and coiled-tubing conveyance of wireline logging tools has cost and risk considerations, for example logging tool hold-up on ledges in rugose hole can result in costly hole conditioning and re-logging operations. More recent advances in conveyance technology, particularly open hole tractors, have provided additional options for conveying open hole wireline logs. However, rugose hole also presents challenges for open hole tractors including limited opening diameters that result in loss of wall contact, effect of contact forces on rugose formations, and ledges that hold-up logging toolstrings.

Starting from a novel physics based modeling approach of the conveyance operation in rugose open hole, and armed with years of logging experience and data, a family of wireline conveyance tools (Fig. 1) were developed and tested to address this challenge. Exhaustive laboratory based testing supported by virtual testing and simulation verified the proposed tool concepts. Intellectual property protection through invention disclosures and filing of patents was then completed. A number of field-worthy prototypes were then developed. Finally several promising field trials were conducted confirming the viability of the developed technology.

Introduction

Hole rugosity, typical of certain formation zones in Qatar's North Field, poses a significant challenge to achieving the RasGas 100% wireline conveyance vision. The main contributors to such hole conditions are ledge effects, and cutting effects. Conveyance through such zones is critical to enable access to the target reservoir. Claystones in this zone are mechanically weak and break out, while neighboring anhydrites, limestones, and dolomites can withstand stresses and remain effectively in gauge (8.5"). This results in sharp transitions between broken claystones and competent rock intervals (ledge effects). It is noted there is insufficient rock integrity in the overall interval to increase mudweight to balance rock stresses in certain weak intervals. As well, increased mudweights would significantly increase logging risks in the reservoir itself. These breakout zones encompass all 360 degrees around the wellbore wall and can contribute to holding-up descent of the toolstring [1–7].
Challenges in Uninterrupted Production and Supply of Gas to Mega LNG Trains
Authors: Kumar P. , Mitra S.
Published: March 2015

The paper will highlight key production and operational challenges with complexity in feeding natural gas to mega LNG trains. The unique feature of Qatar's LNG project is the integrated energy value chain, starting from offshore gas reservoir and wells then all the way to liquefaction, transportation terminal and delivery to international customers. The natural gas starts its journey from giant North Field reservoir; is produced through huge mono-bore wells, flow continues via subsea wet gas pipelines to onshore where it is separated into condensate, water and feed to the world's largest LNG trains. The major ventures Qatargas2 and Qatargas3&Qatargas4 operate gas wells, completed in Khuff reservoir, spread over several wellhead platforms, transport gas through multiple multiphase wet gas pipelines to four mega LNG trains at onshore.

The planning strategy for start from right amount of gas extraction with right composition while achieving uniform draw down at reservoir level continues until controlling gas volume from each well complying with facility design limit, within operating boundaries from flow assurance point etc. Time delay from offshore to onshore through pipeline transfers, must be considered on volume and composition estimation of gas. Several activities on wells, wellheads, subsea pipelines add further complexity to the process.

As gas is becoming the energy of choice for the world community, sharing knowledge and experience of producing and continuous gas delivering to maintain the critical supply chain will add value to the hydrocarbon industry.

The paper is focused on the complexity of factors, challenges of planning and executing supply along with several other factors to this element of big energy supply chain. Multiple boundaries, affecting gas movement need to be respected, monitored and achieved. The responsibility lies in having complete knowledge of all factors, ability and experience to steer through the complex set up; fail proof procedures supported by world class execution style.

Qatargas - World's largest LNG Producer

Qatargas Operating Company Limited was established in 1984 and became the largest LNG producing company in the world, with an annual LNG production capacity of 42 million tons per annum (MTA) in 2011. Qatargas LNG reaches to customers all over the world with LNG production through seven trains, of which four are the largest in the world - known as mega-trains.

Qatargas offshore production is located approximately 80 kilometers northeast of Qatar's mainland and is sitting on the world's largest non-associated gas reserve named Qatar North Field. Qatargas onshore LNG trains are located in northern tip of the country at Ras-Laffan industrial City within a plot of 3.9 square kilometers area.
Spatial Modeling of Jurassic Arab Reservoir Depositional Environments as a Guide to Reservoir Connectivity Anisotropies: An Example from the Dukhan Field, State of Qatar
Authors: Stanley Rowan , Al-Ansi Hussain , Weber L. James , Snow John
Published: March 2015

The Arab C reservoir interval of Qatar Petroleum's Dukhan Field is a prolific oil producer. After sixty years of development activity and with hundreds of logged and cored wells, there is an extensive database of rock, geophysical and production surveillance information available for interrogation. The reservoir hosts an accumulation of carbonate lithologies and textures representing a depositional organization of subtidal, intertidal and sabkha environments. A Transgressive System Tract defines the Lower Arab C, migrating upwards from a complex of beach grainstones to a maximum flooding surface featuring muddy carbonates with sporadic encrustations and associated Thrombolite growths. High frequency parasequences within the overlying Highstand System Tract (HST) of the Upper Arab C form a sedimentological pattern from intertidal to sabkha facies, with increasing prevalence of thin isolated high productivity grainstones.

From a practical engineering perspective, the upper parts of the HST collocate with development uncertainties associated with erratic patterns of producer support from offset water injectors. Core descriptions characterize these intervals as low permeability mud dominated tidal flats hosting sporadic conductive grainstone tidal channels, leeward of beach barrier islands.

Qatar Petroleum has adopted coastal hydrodynamic principles to predict grainstone anisotropic variations. The model for the shelf area has been compartmentalized into depositional tracts based on core descriptions, supplemented by predicted facies at non-cored vertical and horizontal wells using inter-dependent 3D-spatial and 1D log-based fuzzy probability. Vector representations of interpreted tidal flux directions have been used to assign analogy-realistic geometries for beach and tidal channel deposits within an environment of deposition framework. The output distributions reflect a close coupling of control data at wells within the context of sedimentary depositional dynamics, linked to production surveillance. An objective for high resolution 3D static modeling of rock textural and petrophysical anisotropy is the optimization of future infill horizontal wells to maximize IOR sweep efficiency.
Effective Utilization of Smart Oil Fields Infrastructure towards Optimal Production and Real Time Reservoir Surveillance
Authors: Al-Yateem Karam , Al-Amri Meshal , Ahyed Rabea , Aminzadeh Fred , Althukair Ahmed , Al-Khelaiwi Faisal
Published: March 2015

Exploration for fossil fuels has resulted in finding thousands of hydrocarbon fields around the globe for over a century. During this timeframe, technology has advanced in a rapid mode with several innovation milestones in this journey. One of those milestones is the implementation of horizontal, multilateral and complex wells that require best-in-class technology to ensure control of the well for optimum production through downhole devices, such as smart chokes and inflow control valves (ICV). Lately, the concept of an "intelligent field" has been embraced by more and more operators with expectations for higher recovery from the reservoir. In addition, installation of permanent downhole monitoring systems (PDHMS) in both free flowing and wells equipped with electrical submersible pumps (ESP)provides continuous monitoring of reservoir parameters as an indispensable tool for reservoir surveillance. Their installation eliminates well intervention data acquisition operations and reduces nonproductive shut-in time during rig-ups, which enables significant improvement of reservoir surveillance in real-time and focused utilization of resources in manpower, capital and assets.

Saudi Aramco is tackling existing problems through the utilization of technologies from smart maximum reservoir contact (MRC)/multilateral wells and mega-cell reservoir simulation to the implementation of fully integrated intelligent fields and geosteering on real-time mode, all offering a widerange of interdisciplinary domains for development and progression. This paper will discuss the integration of smart sensory and control devices within the company's fields, deployed towards finding the optimal production strategy whether the wells are producing naturally or artificially lifted, meeting the designated targets and providing the much needed flexibility in its operations. The latter is of particular importance in fields that are located in remote, offshore, or near populated areas where safety considerations dictate less human intervention. In addition, effective methodologies of data mining and computational modeling are necessary to attain these goals. Such methodologies are effectively placed to ensure the best utilization of integrated operations, as well as to obtain accurate and useful data flow paths. In a nutshell, the implementation of technological advancements result in a positive impact on field performance in a real time fashion, extending the producing life of wells, harmonizing sweep efficiency and ultimately maximizing oil recovery from the fields.
Clad through Clad: A Mechanical Water Shut Off Solution for Commingled Production from Multilayered Reservoirs
Authors: Bourgoin Sebastien , Sobirin Muhammad , Mahardhini Antus , Nathanael Christian Andriko , Jones Mike
Published: March 2015

A casing or tubing clad is a metal sleeve that can be run by several intervention means into a well to isolate an area of interest, be it to provide a permanent seal over splits, holes, or perforations in tubing and casing or for water shut off. Once it is on depth, the clad or metal sleeve is expanded out against the tubing or casing wall to form a seal.

Taking the example of water shut-off isolation, conventional clad technology only permits a ‘bottom up isolation’, the current technology does not have the ability to pass through an expanded clad of the same size thus it is not possible at a later date to install a second clad below an existing clad.

To resolve this issue, in 2006 TOTAL instigated the development of a "Clad thru Clad" technology through a JIP (Joint Industrial Program) Water Management R&D Project with Maersk, Statoil, Chevron, and BP as partners. Meta was selected to develop the clad through clad technology. The project objective was to design an electric line conveyed clad able to pass through other similarly sized clads previously installed in a well incorporating a metal-to-metal interference fit with elastomer seal against the 5-1/2" production casing or tubing wall.

In addition to the dimensional, pressure rating (5000 psi absolute, 2000 psi differential) and temperature rating (125 degC) constraints, one of the major challenges was to achieve sufficient collapse rating for the clad once expanded.

The Internal Clad™ is deployed using a hydraulic expansion system. The setting tool consists of a standard electric line cable head, an electronic section (consisting of gamma ray (GR), a casing collar locator (CCL), a motor control module and pressure sensors), a down-hole reservoir, hydraulic module (consisting of motor, a pump, an intensifier and valves), and the setting tool itself.

The first trial was performed in Total Indonesia's Peciko field; well C, a gas well producing from a multilayered reservoir. The field trial was SUCCESSFUL although a number of improvements for future operations were identified.
A Tool to Tackle the Challenges of the Treatment of the Back Produced Viscosified Water
Authors: Rambeau O. , Jacob M. , Rondon M. , Jouenne S. , Cordelier P.
Published: March 2015

When the Enhanced Oil Recovery process involves a polymer injection (P, and/or SP), both surfactants and polymer are expected to be produced with production fluid, at different ratio along field life. This means changes of miscibility of fluids versus time, leading to some challenges with regard to the process and its flexibility against time. Depending on the start up of the EOR production through field life, more water treatment difficulties would have to be managed comparing to separation issues; otherwise the efficiency of both water treatment and separation could be partially lost.

This paper is focusing on water treatment technologies assessment regarding inlet characteristics of produced water in presence of HPAM polymer back production. Technologies to be tested have been chosen to tackle expected thinner oil droplets in water emulsion. To answer the request of high quality of water (oil and solids contents targets) for re-injection, water technologies like filtration and centrifugation have been assessed through lab bench screening.

Results are variable depending on technologies and severity of inlet conditions but they look promising. A pilot scale has been designed, a platform of tests has been built to help projects better design their process and subsidiaries optimize existing processes. This platform supplies viscosified water with degraded polymer to mimic field conditions, which is mixed with oil and solids to generate actual field produced water. This recombined back produced viscosified water feeds the open loop for the testing of various water treatment equipment. Oil droplet size is controlled on line as well as oil content. The scale of this platform allows screening of a rather large range of characteristics of back produced water in terms of oil droplet size, polymer content and viscosity, in order to qualify a suitable technology for a given range of operability.
Recent Advancements In Vessel Desanding Technology
Authors: Opawale Adekunle , Abdalla Tarig
Published: March 2015

Production of formation sand and other solids with wellstreams has been a big challenge in the petroleum industry. Presence of sand in the production stream can cause erosion of upstream facilities and - even more commonly - clogging of flowlines and accumulation in production vessels; reducing residence time and performance of separator internals.

Several methods have been applied in the petroleum industry to remove deposited sand from production vessels. Some of the drawbacks with these technologies are: localized sand removal, excessive use of water, interference on vessel liquid levels, compromise of water and oil quality, risks of clogging, huge sand system infrastructural size etc. Direct consequence of these situations would be unmanageable disturbances on production operations, and eventually leading to unplanned shutdown, and production loss.

Recent innovations on design of vessel desanding internals at FMC Technologies are the Dual and Single Vessel Desanding Systems. While the dual desanding system integrates a set of systematically arranged jet nozzles and a novel hydrodynamically designed suction system, the single desanding system is a unique combination of a smart elliptical fluidization technique and suction in a single compact design. This paper presents both technologies, with special focus on their developments and qualifications. Case studies are presented; highlighting the benefits of the new technologies, as well as their application possibilities.

Introduction

Sand and other solid particles are usually produced with oil, gas and water from most reservoirs in the world. In the United States, reservoirs in the Gulf of Mexico, California and Texas tend to produce more sand. Around the world, sand production is common in West Africa, Canada, China, Venezuela Trinidad, Cameroon, Middle East, Indonesia and parts of the North Sea1. The phenomenon of sand production is directly related to any/combination of the following: unconsolidated nature of some reservoirs, high drag forces created by increased produced fluid and accelerated water influx.

As explained by the illustrative schematics in figure 1, disintegrated sand particles from the formation rock matrix are transported up the wellbore, through the production system. Thus unconsolidated sandstone reservoirs would tend to produce more sand particles, especially when the wells are becoming mature, with lots more water influxing. Proppant solids are also produced from wells following fracturing treatment programs.

Although downhole sand control mechanisms are usually in place in most wells, certain cut-size of sand particles would eventually get produced to the surface because wide particle size distributions always exist in the reservoir. This ranges from 1micron to over 10,000 micron. Sand particles produced to the surface leads to a wide range of operational challenges.
Program Acceleration - CASE STUDY
Authors: Al Utaibi Abdulwahed Zayid
Published: March 2015

Introduction / Summary

Karan Gas Program has successfully completed Saudi Aramco's first offshore, non-associated gas development achieving record early gas in 2 years and 3 months with full production in 3 years and 4 months. Figure 1 shows completion of the first offshore non-associated gas production platforms. The Karan gas field is located offshore approximately 110 KM in Saudi Arabian Gulf territorial waters. It was discovered in 2007 and has a production capacity of 1,800 million standard cubic feet per day (MMSCFD) of natural gas.

The Karan Program achieved the corporate objective of maintaining sales gas supply to Saudi Arabia from 2011 onwards by executing the 1,800 MMSCFD non-associated sour gas program. The increased gas supply will be utilized for power generation, water desalination, chemical feed stocks, and as sales gas. The increased utilization of natural gas for domestic consumption decreases the amount of fuel oil required, thereby freeing up that valuable commodity for export and commercial utilization.

In order to meet its business objectives and provide value to its stakeholders, the program was executed under four sub - projects that were developed concurrently. A brief description of these four sub-projects is as follows.
Automatic High-Throughput Detection of Fluid Inclusions in Thin-Section Images using a Novel Algorithm
Authors: Bennetzen M. V. , Marquez X. , Mogensen K.
Published: March 2015

Detection and examination of fluid inclusions can lead to insight into diagenesis and history of a hydrocarbon reservoir. Currently, geologists are faced with a large collection of digital images, making manual investigation highly inefficient and time-consuming.

A combination of data acquisition by simple and robust light microscopy and an advanced downstream computational solution is ideal with respect to cost efficiency and stable large-scale and high-throughput ability. Moreover, a strict deterministic algorithm for automatic fluid inclusion detection is not subjected to any human biases that would otherwise violate detection consistency.

A novel algorithm for fluid inclusion detection has been developed and implemented in the statistical scripting language R and the object-oriented programming language C# under the .NET 4.0 computational framework. The algorithm is a result of thorough understanding of the image representation of fluid inclusions and optimized based on empirical correlations. It is based on sequential image section-specific intensity-centric selection criteria, intensity distribution discrimination and conditional statistics. Moreover, a multi-dimensional scoring-scheme has been developed and implemented.

The software was able to successfully identify a series of fluid inclusions on the same thin-section image containing hydrocarbon and aqueous phases, respectively. Due to the modular structure the software is highly flexible and can be tailor-made to specific analytical needs, such as selective identification of solid phases.

Introduction

Fluid inclusions are present as chemical impurities in virtually all crystals. A fluid inclusion is a microscopic sample of fluid (liquid or gas) that is trapped within a crystal (10–40mm), as shown in Figure 1, preserving a record of the physico-chemical conditions prevalent during the crystal growth. Detailed fluid inclusion examinations, in conjunction with classical petrography and geochemical work, are therefore important to help unravel the diagenetic history of e.g. cements that plug pores and reduce the permeability of reservoir rocks. Calcite and anhydrite cement crystals present in reservoir rocks have been shown to contain fluid inclusions that provide data on the nature, composition, temperature and density of the fluids present during diagenesis and hydrocarbon charge.
The Challenges of Extending the Life of UK Offshore Installations
Authors: Russell Jimmy , Keith Ian
Published: March 2015

The majority of the oil and gas production infrastructure in the UK sector of the North Sea was installed in the 1980's and 1990's. Typically these installations were designed with a lifespan of 15–25 years, and many of them are now at or beyond their original design life. With higher prevailing oil prices, and continued development via subsea field tie-backs, the economic lifespan of these installations look set to exceed design lives by a considerable margin. In addition, many installations are now processing very different fluids and rates as they enter the mature phases of production.

This paper describes in more detail how the life extension challenge is being managed in Shell UK. It covers the overall process being adopted for managing facilities beyond their design life, as well as describing some of the methods and techniques being used to make key decisions. The key learning's that can be applied in other mature fields includes:Dealing with more stringent environmental legislation than was applied when the facility was built;What detailed structural reviews are carried out to extend the design life;When to apply retrospective design standards;Managing the obsolescence of critical systems in particular the control and automation hardware;How to undertake major projects on an operating asset and dealing with the limited accommodation for the construction teams.

A number of Shell facilities in the North Sea are currently going through this process with the learning being applied in more assets in the coming years.