bluuebunny/crossref_metadata_2025 huggingface dataset:
Qatargas Flare Reduction Program
Authors: Bawazir I. , Raja M. , Abdelmohsen I.
Published: March 2015

Qatargas produces 42 Million Tonnes Per Annum (MTA) of Liquefied Natural Gas (LNG). The Qatargas facilities comprise seven LNG Trains, including four of the world's largest mega-trains, which were commissioned between 2009 and 2011. Routine baseline flaring is encountered during normal LNG plant operations due to the essential requirement to maintain purge gas flow within the flare system to prevent air ingress and consequent explosion hazards. During unplanned facility trips, restarts or planned facility shutdowns, process gas is also flared per operational requirements.

Qatargas has made significant progress in reducing flaring from its LNG trains in line with the increased national focus on flare minimization and the Company's desire to reduce its emissions and carbon footprint. This has been made possible through operational initiatives on source reduction, increased plant reliability, reduced shutdown/start-up flaring and a sustained focus on flare minimization facilitated by multi-disciplinary Flare Management Teams (FMTs).

Enhanced acid gas recovery and operational excellence initiatives on source reduction and plant reliability at Qatargas' older, conventional LNG trains have successfully reduced flaring by more than 70% between 2004 and 2011. A comprehensive project is currently underway at the LNG mega-trains to reduce current baseline purge flaring by approximately 70%. Qatargas is also undertaking a long-term capital project to install interconnections between LNG mega-trains to re-route gas encountered during process events rather than flaring. Additionally, Qatargas' pioneering Jetty Boil-off Gas Recovery (JBOG) Project, which will commence operation in 2014, is expected to reduce LNG loading flaring by over 90% and recover approximately 600,000 tonnes per year of flared gas.

This paper provides an overview of Qatargas' flare management approach, the Company's main drivers and challenges for flare reduction and the various initiatives currently underway to manage and minimize flaring. These include the major capital projects noted above as well as enhanced awareness, monitoring and reporting, and operational source reduction successes.

Facility and Flare Systems Overview

Qatargas' LNG operations are based in Ras Laffan Industrial City (RLIC), Qatar, and centered on the four LNG assets described below.Qatargas 1 (QG1): Three conventional C3MR LNG trains (Trains 1–3). Commenced operations in 1996. Each train has a production capacity of 3.3 MTA (total QG1 production of 10 MTA). Offshore facilities include the manned North Field Bravo (NFB) complex with three wellhead production platforms.Qatargas 2 (QG2): First mega-trains in the world, each with a capacity of 7.8 MTA. Commenced operations in 2009. Both trains (Trains 4 and 5) utilize the Air Products AP-XTM hybrid liquefaction process which allows for higher LNG production by adding a third Nitrogen (N2) refrigeration cycle to the conventional C3MR process. Offshore facilities include three unmanned wellhead platforms.
Assessing the Biotreatability of Produced Water From a Qatari Gas Field
Authors: Janson A. , Katebah M. , Santos A. , Minier-Matar J. , Hussian A. , Adham S. , Judd S.
Published: March 2015

Biological treatment is generally regarded as the most cost-effective method for the removal of organics from wastewater. Biotreatment of produced water (PW) presents many challenges when compared with municipal wastewaters or industrial waste streams. These challenges are typically linked to its high level of organics (including refractory organics) and salinity which can dramatically reduce biological floc formation and biomass settle ability in conventional clarifiers. In a membrane bioreactor (MBR), an ultra filtration membrane separates the treated water from the biomass and settleability is not a factor.

This paper summarizes the results of tests conducted in Qatar with three parallel bench-scale membrane bioreactors to assess the biotreatability of PW from a local gas field. The testing was partially funded by Qatar National Research Fund which is testament to the importance of the research and the value it brings to Qatar and the world.

The test program followed a Box-Behnken experimental design requiring 13 separate tests with input parameters of hydraulic retention time, solids retention time and temperature and response parameters of % COD removal and oxygen uptake rate (OUR). The results indicated ˜60% of the COD is removed through treatment in a membrane bioreactor. Statistically, only SRT was shown to be a factor in the percentage COD removal. At an SRT of 60 days, the average percentage COD removal was 62%, 4% higher the 58% average COD removal obtained at an SRT of 120 days. The OUR ranged from 0.10 to 0.19 mgO2/L-min and was shown statistically to be only dependent upon HRT with the highest OUR obtained at the shortest HRT of 16 hours.

It is concluded that if biotreatability is shown to be cost-effective, it can contribute as part of an overall system to treat PW prior to recycle or reuse. This can reduce the facility's demands for fresh water and can thereby make existing potable water supplies available for other important uses.
Driving Continuous Performance Improvement in Qatar
Authors: Akyabi Khalid , Clancey Byron , Yurkiw Frederick , Babb Jonathan , Chisholm Colin
Published: March 2015

RasGas Company Limited has been utilising the ExxonMobil Fast Drill Process to drive continuous improvement in drilling operations in Qatar's North Field since its roll-out in 2005. Implementation of the process has resulted in significant increases in drilling performance and unique changes in operational practices. In recent years, continued North Field development in new areas has introduced unique challenges requiring innovative drilling solutions to continue to raise the bar in drilling performance.

This paper details how RasGas has utilised the Fast Drill Process to identify and extend new performance limiters in wells of increasing drilling complexity. It also details the development and roll-out of a new Flat Time Reduction initiative that targets performance improvement in areas previously untouched by the Fast Drill Process workflow.

The combined impact of these initiatives has resulted in another step change in performance and well delivery in more complex areas of the North Field. The performance improvements have accumulated cost savings in excess of $250 Million USD for RasGas and its Shareholders and have been achieved while maintaining and building upon an industry leading safety record.

The performance improvement initiatives described in this paper are applicable for any large scale drilling campaign that requires increased Rate of Penetration (ROP), reduced plateau times, and accelerated well delivery.
Greenhouse Gas (GHG) Emission Verification at Ras Laffan City (Case Study)
Authors: Buhidma Abdullah M.
Published: March 2015

Qatar Petroleum is implementing an accurate and auditable procedure for the Accounting & Reporting of Greenhouse Gas (GHG) emissions within Ras Laffan Industrial City (RLC). The procedure is based upon proven European practices and international and industry proven guidelines and methodologies in determining emissions caused by CO2, CH4 & N2O as a result of process combustion, acid gas removal/generation and flaring. Participating companies are all Oil & Gas processing companies and Power and Water Generation companies in RLC with combustion installation having a fuel rated input exceeding 20 MW.

Each participating company submits quarterly & annual GHG emissions reports supported with accounting & reporting plan and spreadsheet calculations for verification by an accredited third party verifier hired by Qatar Petroleum. As a result, a Positive Verification Opinion & Statement are issued by the same verifier for each participating company that had proved it's compliance with the requirements of the applied QP GHG procedure and international guidelines.

This paper describes the initiative that Qatar Petroleum deployed in the preparation for the GHG verification process and the implemented methodology in accounting & reporting of GHG emissions at RLC, the achieved progress in uncertainty of the reported GHG data in three consecutive years (2010 - 2012) and the lessons learned for future improvement. The role of Qatar Petroleum in initiating, monitoring & control of GHG emission verification at RLC is also addressed in this paper.
DIET: An Integrated Approach of Getting The Right Data and Maximizing its Value
Authors: Al-Kharaz H. , Farooqui M. Z. , Ansari A. M. , Blackall D. , Martin M.
Published: March 2015

Well and reservoir surveillance data gathering activities can present a number of logistical challenges and operational risks associated with well intervention work, especially in offshore sour gas fields. This paper describes an approach adopted by RasGas Company Limited (RasGas) to reduce these risks by implementing a workflow that facilitates full integration of the acquired data to maximise its value and improve the understanding of well/reservoir performance. Hence, the workflow is used to arrive at a need-based strategy to plan, design and execute yearly well/reservoir surveillance programmes.

The need for early well and reservoir performance data when a new gas field is placed on production often necessitates a calendar-based and broadly applied surveillance programme to develop reservoir deliverability and well productivity trends across the field. These baseline data are used to proactively identify and quantify potential threats to well productivity and production sustainability from issues such as skin build up from scale or condensate banking, unexpected formation water production, corrosion damage, etc.

Once the sufficient baseline data set has been acquired, there is a need to develop an optimum approach towards well and reservoir surveillance programmes. This ensures that surveillance programme is focused on delivering truly needed data while reducing the risks inherent to well intervention activities. RasGas achieved this optimisation through development of a workflow called "DIET" (Data Integration and Evaluation Technique). Implementation of DIET has significantly reduced the reliance on a set-frequency logging strategy, thus reducing overall well intervention job counts, costs and risks. In addition to integrating all relevant data for single well evaluation, the DIET workflow is also being expanded to enable field-wide data integration.
Acoustic Velocity Measurements and Interpretation for Challenging Fluid Systems
Authors: Lewis Edward , Odikpo Greg , Dindoruk Birol
Published: March 2015

Acoustic velocity can be measured with a high degree of accuracy making it an attractive method for extracting related thermodynamic properties. Technical improvements were made to measure acoustic wave velocities in fluid samples over a range of temperatures, pressures, and fluid properties. The simplicity of this technique relative to conventional PVT measurements makes it a fast and reliable means for obtaining some of the data needed in petroleum engineering calculations.

The primary objective in this study is to determine whether the designed apparatus is suitable for measuring compressional wave velocities in fluids commonly encountered in oil and gas operations. Additionally, the potential of the device to be used as a QC tool to accompany conventionally determined PVT properties was also studied. A robust experimental design allows for the determination of acoustic wave velocities at elevated pressures and temperatures and includes the ability to homogenize and recondition samples. For experiments involving heavy, viscous oils - especially those containing dissolved gas - this capability is particularly important.

The following main points will be the focus of this study that also includes new data interpretation:Ultrasonic p-wave velocities in two heavy oil samples were measured up to 10,000 psig: A live fluid was diluted with solvent and the acoustic response was measured for two solvent dilution levels (8 and 20 percent by mass). Velocity decreased with increasing solvent concentration. A light hydrocarbon mixture was blended with a bitumen sample in a dilution range of 10 - 60% by mass. Velocity again decreased with increasing solvent concentration.
SHE&S Excellence and Innovation for the Barzan Onshore Project
Authors: DeHart R. E. , Brand J.
Published: March 2015

The Barzan Onshore Project is being developed by Barzan Gas Company Limited, a joint venture between Qatar Petroleum and ExxonMobil Barzan Limited, with RasGas assigned to develop and operate the facilities on completion. The Engineering, Procurement and Construction (EPC) work is being carried out by JGC as the prime contractor. JGC has sub-contracted the construction execution of the work to eight major sub-contractors. The project has achieved over 90 Million Safe Man-hours since July 2012 when the one lost time incident project to date occurred. The workforce is approaching 29,000 persons from multiple countries.

The paper describes the overall SHE&S Management System as a three-tier model based on the EPC contract in which there are 211 SHE&S contract-related deliverables (in eight general categories) measured monthly via the SHE&S Work Activities Schedule. The system pertains to all parties (RasGas, JGC, sub-contractors, vendors, suppliers, et al.) and this rigorous monthly accounting helps drive overall SHE&S performance. The contract combines a highly prescriptive as well as goal-setting approach, which to date has delivered a great foundation to build and sustain SHE&S performance at site.

Within the paper, some of the key leading and lagging indicators are reviewed to demonstrate the correlation between the scope of work, stage of project execution, progress and key injury trends occurring at the site. The indicators are actively utilised on the project, especially the leading indicators to drive and sustain SHE&S performance. Six stellar areas and six challenging areas are also reviewed. The stellar areas demonstrate some of the key best practices that are implemented on the project and are producing strong results. The six challenging areas demonstrate some of the complex problems on the project and the methods that are used to improve these problem areas and help ensure that sufficient risk reduction measures and actions are being implemented.

Overall SHE performance on the project continues to be strong although there are daily challenges. These challenges are overcome by a strong management commitment as well as a worker-focused programme that continually demonstrates care and concern for the project's most valuable asset, the workforce.
A Fresh Look at Thin-bed Prospectivity Within Conventional Shallow Water Clastic Plays; Implication for Significant Bypassed pay
Authors: Dashti Rouhollah , Basu Debnath , Dahlan Athirah , Kyi Ko Ko
Published: March 2015

Thin-bedded sands in shallow water clastic deposits are widely neglected as exploration targets simply due to conventional wisdom that focuses more on the "charismatic" blocky clean sand packages. In addition, the lack of a strong, characteristic motif on the log response and complexity in quantitative characterization of these thinly laminated sequences leads to even less attention to such sequences as potential targets. This can have significant impact on the certainty of realistic reserve calculation in exploration and development planning in regions such as Southeast Asia where these thin-bedded sands are a considerable portion of the stratigraphic column.

This study has two phases; in the first phase, a novel technique is presented to identify and quantify thin sand laminations using borehole images and core. Both borehole image and core data is converted to binary data representing shale and sand facies. Then these images are used to quantify the total thickness of thinly-laminated sands on the basis of specific cutoff values. In the second phase, a comprehensive analysis of a local present-day analogue determines the possible hydrocarbon storage capacity of thin-bedded deposits. This is accomplished through an area/volume approach. In this approach, after locating the pertinent locality within the depositional environment that can be considered as the equivalent to the subsurface section under study, the sand volume vs. area of thin-bedded heterolithic facies is computed. This is used to estimate the storage capacity of these facies at the field-scale. Additionally, the storage capacity is compared to the capacity of channel-fill sands as conventional targets in the same setting.

Results of this study show that the new technique using high-resolution borehole images can successfully identify and quantify thin-bedded sands, and results have an excellent match with core data. Also, the core results confirm that these deposits have sufficient reservoir quality (porosity and permeability), particularly for gas production. This work demonstrates that, contrary to conventional belief, the storage capacity of thin-bedded sands can be significantly high and sometimes may even exceed that of blocky channel or mouth-bar sands. This implies that substantial quantities of pay are continuously bypassed in basins where these sequences are expected.

Introduction

Hydrocarbon accumulations in thin-bedded reservoirs constitute a significant part of many newly discovered fields. These are predominantly deepwater turbidite prospects, which lack thick, readily-recognizable sand packages and require much effort in thin-bed reservoir analysis. However, similar types of sediments often occur in many other depositional settings, including coastal and shallow water environments. The impact of thin beds on hydrocarbon pore-thickness has been well documented in tidal environments as well (Passey et al. 2006; Fig. 1).
Helium 2 - A New Dimension to Energy Resources
Authors: Al-Harbi Marwan
Published: March 2015

Qatar is destined to be the world's largest helium exporter by 2013 when the world's largest helium refining unit begins to produce its first drop of liquid helium. The new unit Helium 2 facility will join the existing Helium 1 facility to provide more than a quarter of worldwide helium sales.

On behalf of RasGas and Qatargas owners, the RasGas and Qatargas Helium 2 Project Teams have built a state-of-the-art facility where crude helium is extracted from six Liquefied Natural Gas (LNG) mega trains. Crude helium is transported by pipeline to a helium recovery unit, refined to 99.999 percent Grade-A purity, liquefied, and loaded into containers for shipment to three main customers. The new extraction facilities will also include equipment to oxidise trace amounts of methane from the feed stream in order to minimise the project's environmental footprint.

Qatar's helium is produced as a by-product from the LNG trains. Capitalising on economies of scale, large volumes of helium are extracted for export, further strengthening the market position of the project's shareholders and providing flexibility to meet future demands.

Helium is used in various applications such as medical scanners, academic laboratories, diving, space exploration, and leak detection. In cryogenic applications where extremely low temperatures are required, there are no known substitutes for helium, making it a strategic long-term resource.
Two Strategies for Attenuating Internal Multiples in Land Data
Authors: Retailleau M. , Shorter J. , Farran H. , Hugonnet P. , Wa Hong T. , Benjamin N. , Pica A.
Published: March 2015

Two new internal multiple attenuation methodologies are presented. The first approach uses a 3D wave equation based multiple modeling technique followed by 3D adaptive subtraction. The recorded data are back propagated/propagated through a reflectivity model (obtained from a preliminary migration) of the overburden. All possible multiple raypaths are modeled by using different combinations of two sub-windows in this reflectivity model. Each combination results in a specific multiple model. The generated multiple models are then simultaneously adapted and subtracted from the input data. The second approach is a 3D dip extraction and filtering technique, taking advantage of any dip discrimination between the primaries and multiples. It works on post stack and pre stack volumes. We show how the two methods are complementary and how they can be combined.

The first approach can be applied to any seismic data plagued with strong internal multiples and is perfectly adapted to modern dense, wide azimuth surveys. The second approach works on any seismic volume in which multiples and primaries have different dips in a given domain.

Some real data examples from South Oman 3D seismic datasets are shown. All are characterized by a heavy multiple contamination, generated by strong shallow reflectivity sequences in a flattish overburden, and overlying deeper, weaker and heavily structured primaries. By revealing structures previously invisible, these techniques add a lot of value to existing seismic data sets.

The generation mechanism of internal multiples is often quite complex making them difficult to predict. The main benefits of the methods described here are that they work in absence of move out discrimination and without the need of a precise identification of the internal multiple generators.

Introduction

In some areas of Middle East, it is common to have shallow carbonate sequences with strong reflectivity, high velocity contrasts, overlying lower reflectivity clastic series with weak impedance contrasts and lower velocities. This geologic sequence yields a heavy contamination of the lower unit by energetic interbed multiples generated in the upper unit ("curtain of multiples"). These multiples often have the same, or higher apparent velocity, than the primaries, offering no opportunity to remove them by move-out discrimination. Similarly, prediction methods (gapped deconvolution) have proved unsatisfactory. And in addition, it is mostly impossible to identify clearly the generators, given the large number of possible candidates.

Historically these unwanted multiples have been removed by surgical 3D FK filtering after flattening of the suspected multiple generators. This method has been used for many years but has several strong limitations, in addition to the well known FK artifacts. Hence new methodologies were required to overcome the failings of this 3D FK approach.
From a Project-oriented to an Operations-focused organization - The case of QG OPCO Well Engineering and Intervention Division
Authors: Paez Tomas J
Published: March 2015

Qatargas (QG) OPCO experienced an impressive growth in the last 6 years, starting with QG2 in 2006, and followed by QG 3&4, QG1 first in-fill drilling campaign, and finally QG1 second in-fill drilling campaign in 2012. These projects helped QG OPCO become the biggest LNG producer in the world. The sudden expansion did not allow the Well Engineering and Intervention (WEI) Division to easily assimilate the changes. Even though WEI grew in size (i.e. number of personnel) by recruiting global talent, this accelerated growth demanded a different approach to develop organizational capabilities (resources and processes) to operate the new well count.

In 2012, WEI embarked on multiple initiatives to transition from a Project-oriented to an Operations-focused organization. The first initiative was related to the need for one overarching Well Integrity Management System since different criteria and procedures were utilized in each of the ventures. The second initiative addressed the need for a Well Control and Blowout Prevention Manual and Contingency Plan to prevent and mitigate well control situations in scenarios where Jack Up availability and Drilling organizations were limited (drilling organizations set up to expand QG OPCO were reallocated, downsized or dismantled). In addition, a new WEI structure was required in order to gain efficiencies, align personnel with business needs, and sustain or develop capabilities in the workforce.

This paper discussed the journey of WEI in pursuing organizational capabilities in order to meet ever-demanding global energy challenges and QG OPCO vision - to be the world's premier LNG Company.

Introduction

The North Field, discovered in 1971, is the largest non-associated gas field in the world with estimated reserves exceeding 900 TCF. Qatargas is one of the four companies operating in the North Field. Since Qatargas establishment in 1984, the State of Qatar has become the biggest LNG producer in the world, providing reliable energy security globally and operating the biggest LNG shipping company internationally. Today, Qatargas is the largest LNG producing company in the world. Its role in producing North Field resources has a significant impact on the State of Qatar and the global LNG markets.
Systematic Evaluation of Asphaltene Formation Damage of Reservoir Fluids from Lake Maracaibo, Venezuela
Authors: Memon Afzal , Borman Craig , Garcia Martha , Reyes Tristancho Dayana Judith , Ratulowski John , Gao Jinglin
Published: March 2015

One of the most concerning areas for asphaltene deposition is the near-wellbore region, where such deposition causes formation damage. The reservoir fluid of the Lake Maracaibo region is known to experience operational problems due to asphaltene deposition inducing production losses. A detailed asphaltene formation damage investigation was performed on the live oil samples from the Lake Maracaibo area. An unusual asphaltene precipitation envelop was observed for this fluid and reported in an earlier publication (Gonzales et al., SPE 153602, 2012). In the current paper, we focus on the systematic evaluation of asphaltene formation damage using stacked composite core samples.

A special coreflood system was designed for an asphaltene formation damage study using reservoir core samples and sour-live reservoir fluid samples. The effect of flocculated asphaltene in the porous media was evaluated as the reservoir pressure decreases below the asphaltene onset pressure (AOP). Live samples were collected and flooded through the stacked composite core plugs under reservoir conditions. Progressive pressure reductions were performed to induce asphaltene precipitation in the porous media. Oil permeability changes were measured to evaluate the effect of this phenomenon in the reservoir using composite core. Significant impairment of composite core was caused by the depressurization of the reservoir fluid below AOP. The inlet pressures of the composite core stack were maintained just above AOP and the outlet pressure approximately 50 psi above saturation pressure throughout the core flood experiment. Thus, asphaltene precipitation onset occurred inside the composite core.

This experiment showed significant permeability loss in the composite core after sufficient flooding of live oil fluid. Following the core flood experiment, the core stack was depressurized, and the remaining hydrocarbon was extracted from individual core plugs. Detailed chemical analyses were performed on the extracted hydrocarbon deposits from individual core plug with various analytical techniques, such as asphaltene content, simulated distillation, optical density, and thin-section analysis. These analyses' results confirmed that the observed oil permeability loss was indeed due to the formation of asphaltene deposit inside the porous media, and the asphaltene deposition was somewhat more extensive in the tighter core sections.
How to Manage CT operations in Hostile environment: Field Case Studies on CT Challenges in Deep HPHT High Sour Carbonate Formations.
Authors: Packirisamy Packirisamy , Al-Bader H. , Al-Salali Y. , Vidyasagar Vidya Sagar , Manimaran A. , Al-ibrahim A. R. , Rajkhowa A.
Published: March 2015

Objective of this paper is to present our recent case-histories involving uncommon and unexpected Coiled Tubing (CT) intervention challenges in exploratory wells while testing and stimulating deep HPHT high Sour carbonate formations.

Jurassic formations at around 17,000 feet in Kuwait are tested using cased-hole Drill Stem Testing (DST) system. 15K CT is employed during DST for displacement of kill fluids to achieve under balance prior to perforation, placement of acid for stimulation and for well killing operations. CT operational challenges encountered during testing deep exploratory wells are high pressure reservoir(>10,000 psi), limit on CT injection pressure>10,000 psi, pumping acid of 28% HCL, sour well fluid, salt plugging, etc. Well intervention under such challenging conditions requires proper planning, right equipment, techniques and procedures to ensure safe operation. Existing challenging conditions were well managed and objectives were met.

A new problem of formation solids production after acidization of Kerogen rich carbonate/shale formation created a new challenge for CT operations which is unlike the common problem of sand production from the unconsolidated sand stone formation. In some wells, DST string got plugged with solids after acid stimulation and obstruction/stuck-up was encountered while operating CT. Another unexpected problem is the high H2S concentration of 35% in the recently discovered field. The unexpected challenges created unwarranted situation. It is a challenging task for operators to execute the safe and successful CT operations under these uncommon and unexpected conditions. Initially, even some of the service companies expressed their inability to operate CT under these extreme conditions.

The unexpected problems are managed well within the available resources and the well test operations were executed safely and successfully. The new solids production operational experience has helped the operator to avoid the reoccurrence of CT stuck up thereby decrease the operational risk and increase the success rate. It has been proved practically in the field that CT can safely be utilized in high sour wells up to 35% H2S and increased the operator confidence.

The experience gained, new challenges encountered, safe practices followed and way forward for execution of successful coiled tubing intervention in hostile environment will be discussed in this paper.
Proactive Casing Leak Detection Methodologies: A Case History
Authors: Al-Khamis Mohammed N. , Al-Yateem Karam , Kima Enow A.
Published: March 2015

This paper addresses how high resolution electromagnetic induction was used to study, assess and map the overall well casing integrity of offshore wells and to enable predictions of casing leakage based on the extent or severity of the casing corrosion log. The objective of the paper is to show how proactive detection and prevention of leaks before they occur have guaranteed continuous operation excellence, safety and environmental compliance.

These studies were carried out to understand the nature of the corrosion observed. In addition, several other technologies were deployed to effectively detect leaks and further sketch out their location. The lessons learnt and experience acquired during the monitoring and evaluation of casing integrity will be shared.

The new technology was used as a tool to establish a casing integrity baseline for an entire field and articulated the new strategic corrosion master surveillance plan. Using the new technology has resulted in a significant reduction in the frequency of routine conventional temperature surveys and therefore optimized resource utilization to foresee other essential jobs.

Introduction

Issues associated with casing leaks can lead to significant losses of oil or gas reserves as well as momentous pollution problems. Therefore, early detection of the leaks as soon as they occur is very crucial. In Saudi Arabia oil fields, casing leaks are of particular importance since the country holds some of the largest reserves of petroleum in the world1. The problem is of variable severity from one field to another, depending on the conditions encountered. The sensitivity increases when the field is mature.

A thorough investigation of all factors — influencing the life of the casing — and their correlation with field data has been conducted for a particular field. In addition, over the years engineers have improved their detection techniques. In this paper, the effect of all factors influencing the life of the casing and casing leak detection methods used are discussed.

Safety, asset integrity, monitoring, detection and possible maintenance and/or repairs of leaks as a result of corrosion are paramount. The conventional technology to detect leaks is the temperature survey, which identifies either up flow or dumping leaks. The method is executed on quarterly basis to identify any casing leaks in a timely manner. If the temperature profile is suspicious, well head samples are collected to carry out further investigation and testing. Annuli survey is conducted bi-annually in addition to temperature survey.

This average production casing life has improved with the new proactive approach to monitor and maintain the integrity of production casing in the field. Other practices that help enhance the strategy include improving cementing practice, selecting chrome 13 casing types across corrosive aquifers, and completing new and workover wells with tubing downhole packers to isolate and protect potable aquifer water from contamination.
Enhanced Reservoir Characterization with Horizontal Well Logs in Dukhan Field, Qatar
Authors: Al-Naama Abdulla , Al-Sahlawi Adel , Stanley Rowan , Albotrous Hilal , Ekamba Blaise , Guo Pingjun
Published: March 2015

Over the last decade, horizontal drilling has played a significant role in the development of the Dukhan field in Qatar. Optimal placement of high-angle and horizontal wells has ensured economic hydrocarbon production in the Arab oil reservoirs. In the Arab C reservoir interval, stratigraphic layers are generally thin and exhibit a high degree of lateral variation in rock properties and low to medium permeability. Horizontal producers with long lateral sections have increased ultimate recovery by providing greater penetration of oil columns above oil water contacts and by tapping attic oil and isolated reservoir compartments. Sweep efficiency has also been improved through horizontal well waterflood programs.

Advances in rotary steerable drilling and logging-while-drilling (LWD) technologies for horizontal wells provide new types of data that can be used for improved reservoir characterization and geologic modeling. LWD sensors are used at Dukhan to acquire real time petrophysical measurements and LWD image logs are now routinely acquired along with conventional triple combo logs (density/neutron/resistivity). A specialized workflow was developed to utilize the LWD image data in log interpretation. This workflow consists of interpretation modules that can be used to define formation bed boundaries and quantify formation property variations along horizontal wellbores. These definitions of 3D bedding structure data and formation properties are then used to condition the geologic model structure and update cell properties.

Image logs and petrophysical interpretation results from several horizontal wells will be presented. Comparisons with offset vertical wells are made to illustrate the added value of using horizontal well data in reservoir characterization. Significant uplift in geological modeling is also achieved by incorporating lateral property variation identified through horizontal well petrophysical evaluations.

Introduction

Dukhan Field, discovered in 1939, is one of the major oil fields in the Middle East region. The first discovery wells were based on field mapping of the Dukhan anticline (Trabelsi et al., 2009, Stephens et al., 2009). The field forms a north to southeast trending anticline that is 70 km long and 8 km wide (Figure 1A). The anticline culminates in four distinct domes, which roughly correspond to the major divisions of the field. These are, from north to south, the Khatiyah, Fahahil, Jaleha, and Diyab sectors (Figure 1B). A series of extensive studies have been done to characterize the environments of deposition and to define a consistent sequence stratigraphic framework (Figure 2). Production of the Arab C and D reservoirs started in 1949 and has progressed through various phases of the oil field development.
Field Study: Impact of Risk Mitigation Systems and Solutions on the Fluid Sampling Success Rate and E&P Project Economics of a Large North Sea Field Development Project
Authors: Castillo Homero , Scott Graham , Wills Phil
Published: March 2015

This paper documents the outcome of an eight-year field study that confirmed how the consistent use of innovative conveyance methods and technologies significantly improved the success rate of fluid sampling programs while reducing the overall cost of the E&P projects in long-reach challenging wells part of the largest development project undertaken in the last 25 years in the UK, North Sea sector.

The formation properties encountered by these wells along their trajectories, including long deviated sections, posed massive challenges to the acquisition of critical formation evaluation (FE) data, core samples and representative formation fluid-samples required in these wells.

In the early stages of this field development, the most significant risks encountered were differential sticking of the wireline-conveyed sampling tools and differential sticking of the wireline in very permeable reservoir rocks. The direct consequence of a stuck sampling tool is the need to fish the sampling tool first and then recover the required fluid samples using pipe-assisted wireline conveyance methods, a sequence that typically takes five additional days. The additional cost to the Project Partners is $4.0 million, based on five days rig spread costs plus the deferred production revenue losses resulting from the five-day production delay of all development wells not yet drilled/completed from the same installation.

During the first eight fluid sampling operations in the development phase of this field the fishing rate was as high as 25%. The development and adoption of modern methods and technologies to manage the conveyance risks identified when performing coaxial packer sampling in 2012 resulted in no wireline fishing jobs (0% fishing rate) and no pipe conveyed logging (PCL) operations required (0% PCL rate) on these UK North Sea projects.

The structure of this paper follows:Overview of the oil fields and the development programs subject of this paperCharacterization of the conveyance hazards present in the wells where the wireline logging jobs subject of these paper were executedDetailed description of each of the key wireline risk-reduction technologies used through the duration of these field developments and the roles they played on the success of the wireline logging jobsConclusions and recommendations for similar field developments on wireline risk mitigation
The Systematic Closing of the Performance Gap in Hydraulic Fracturing
Authors: Bychina Maria , Guk Vyacheslav , Wolcott Don , Economides Michael J.
Published: March 2015

Hydraulic fracturing is the overwhelming completion method in the international petroleum industry. It is estimated, that today it has become a $20 billion industry. It is also one of the most challenging enterprises, incorporating scientific information from geology, reservoir and production engineering, rock mechanics, complex fluid rheology and field economics.

More than a decade ago we introduced the concept of Unified Fracture Design (UFD) as a means towards physical optimization. Since then UFD has been adopted by a great number of practitioners and hundreds of papers have been published. Not all approaches have been successful, nor have they been done appropriately. In this work we relook at the whole issue in a systematic way.

We have identified and describe here a 9-step sequence to mitigate the gaps and help in the optimized field application of modern hydraulic fracturing. These include:Required minimum reservoir characterization: Typical log description.Estimate of k, h, interlayer stress contrast, distance from water.Optimization of fracture size using UFD. Maximum dimensionless PI at optimum conductivity. Optimization of drainage shape and stimulated reservoir volume (SRV).Unique monitoring execution, other than the traditional net pressure or injection variables. New benchmark indicators are used, cross-plotting descriptive variables such as: level of pressure vs. volume of fluid injected vs. operational characteristics, such as tip screen-out.4. Fracture injection tests, designed for fluid efficiency, closure pressure, leak-off coefficient and the newly developed capability for after-closure analysis for well and reservoir variables.For multifrac applications such as shale gas, horizontal wells in very low-permeability formations, zonal isolation and perforation strategies are essential issues.Design of injection schedule to accomplish the desired fracture geometry is the next concern. What happens if things go wrong? The strategy of contingencies must be in place before the execution starts.On-the-fly redesign responding to contingencies, such as net pressure constraints and formation barriers. Ability for alternative plans quickly.Once the job is completed the next step is whatever is necessary to close the fracture and flow the well back. What needs to be done in different geologic settings?Finally, to close the circle, performance evaluation is indicated, which involves comparison between actual performance and expectations and the definitive reconciliation of any discrepancies.
Modeling Bitumen Presence and Its Impact on Reservoir Performance in the Arab D Reservoir, Dukhan Field, Qatar
Authors: Hasiuk Franek , McKinney Andy , Meek Fred , Dwiyarkoro Broto , Jamieson Hank , Al-Ansi Hussain , Miller James K.
Published: March 2015

A recent integrated geologic modeling and reservoir simulation history-matching effort in the Arab D Reservoir, Dukhan Field, Qatar, has found that the presence of bitumen and the extent to which it saturates porosity and impairs permeability are the key factors in matching water production history in wells located near the oil-water contact (OWC). By using production data, the ability to predict the location and continuity of permeability-reducing bitumen was greatly increased.

In this study, many past attempts at visual and petrophysical identification of Dukhan Arab D bitumen were quantitatively compared, and visual macroscopic core descriptions were found to be the most accurate. By integrating core and petrophysical data with the structural history and the timing of hydrocarbon migration and bitumen generation, a predictive model was constructed to identify the part of the reservoir most likely to contain bitumen, the "bitumen prone interval" (BPI). Within this interval, the presence of bitumen was determined stochastically away from well control using facies modeling techniques. In each bituminous cell, bitumen saturation was calculated through statistical analysis of core plug porosity data from inside and outside the BPI. The resulting reservoir model provided both a conceptual match to the working knowledge of bitumen distribution at Dukhan and a directional match to the overall field production history. However, this approach was unable to match individual well performance or the variability in areal sector behavior with a high degree of accuracy.

While direct observation of bitumen is limited to cored wells, producing wells above the BPI provide indirect evidence of bitumen presence for model calibration. Through iteration with the dynamic reservoir simulation model, bitumen distribution, saturation, and permeability were modified systematically within the predicted BPI to better match the behavior of both individual wells and areal sectors of the field.

Introduction

Bitumen is an aspect of reservoir quality that can have significant impact on fluid flow in a reservoir. However, characterizing bitumen distribution and saturation is a non-trivial task due to its petrographic, petrophysical, and geochemical complexity. While the appropriate modeling of reservoir bitumen is challenging, it is not outside the abilities of modern petroleum geoscience. Bitumen was a key parameter chosen for inclusion in constructing a new three-dimensional geological model for Dukhan Field because of its potential for improving the history match.
A Study of Acoustic Wave Propagation inside Cemented Production Tubings
Authors: Farraj Abdallah K. , Miller Scott L. , Qaraqe Khalid A.
Published: March 2015

Well operators use advanced downhole telemetry systems to monitor the flow rate, temperature, and pressure inside the well. The wired telemetry tools are currently popular in the industry although these tools have cost, maintenance, and reliability issues. Acoustic waves that propagate by vibrating the pipe's body inside the well were recently considered as an alternative technology. However, the bottom segment of the production tubing is encased in concrete in many wells; a previous work showed that concrete segments attenuate the acoustic waves to impractical levels, which limits the applications of this mode of propagation.

As an alternative to vibrating the tubing body when there is a concrete segment over the pipe, this work investigates the use of the production tubing's interior as a communication medium for the acoustic waves. A testbed was designed using five segments of 7-inch production tubing to form a pipe string, a speaker to generate the acoustic waves, and a directive microphone to receive the acoustic waves propagating inside the pipe string. To study the effect of cemented pipes on acoustical wave propagation, the third pipe segment was encased in concrete. Input frequencies from 100 Hz to 2000 Hz were investigated; wave measurements were taken along the pipe string, and measurements were analyzed to extract information about the behavior of the acoustic channel.

This work shows that acoustic waves are not affected by the presence of the concrete segment. Low-frequency acoustic waves experience very little attenuation as they propagate through the interior of the pipe string, signal dispersion is not an issue for most frequencies, and delay spread measures increase as the acoustic waves propagate down the pipe. This work advises that acoustic-wave technology can be a promising cost-effective and reliable solution for wireless downhole communication systems.

Technical contributions include: characterizing the channel response to different input frequencies along the pipe string, investigating the power spectral density and signal-to-noise ratio measures, and studying the time dispersion parameters of the channel.

1. Introduction

Wireless communications is a discipline that has widespread applications in different industrial areas. The gas and oil industry is one of the recently growing areas for potential applications of wireless communications technologies. Such technologies can be used for addressing issues in exploration, drilling, and production stages. For instance, well performance and production efficiency can be enhanced by having a means to communicate between surface and downhole tools. Readings of typical well data like oil/gas flow rate, pressure, and temperature can be helpful in monitoring the performance of the wells.