bluuebunny/crossref_metadata_2025 huggingface dataset:
A Case Study of the First High-Temperature Unconventional Reservoir to be Drilled and Logged on Land in the UAE
Authors: Hamdy Ibrahim , Shamsi Juma AL , Mahmoud Gehad , Aref Naveed , Reyami Mazin Al , Hosani Mohamed Al , Azzam Samer , Wahsh Mahmoud , Mossallam Kareem , Diab Emad , Lotfy Amr , Madeeh Eslam
Published: November 2015

The future of hydrocarbon production has shifted toward the significant production potential of unconventional reservoirs. As the recovery of oil and gas becomes more complex, drilling through unconventional reservoirs pushes engineering boundaries to new limits to meet world demand in a safe and environmentally acceptable manner.

ADCO decided to drill Well XY-123 in "XY" field in Abu Dhabi. ADCO leveraged extensive experience gained from numerous unconventional reservoir projects throughout the world in addition to the experience obtained from drilling over 1,000 wells in XY field.

The main objective of the well was to acquire as much data as possible to create a database of knowledge for accurate study of the hydrocarbon potential in these reservoirs. Various formation evaluation data (density, neutron, resistivity, gamma ray, and sonic) were acquired from both logging-while-drilling (LWD) and logging using TLC. In addition, formation pressure sampling stations were also extracted from the reservoir. Conventional cores were successfully cut, with a 100% core recovery rate. Full data acquisition across the reservoir was obtained by the ADCO for the first time.

Drilling such wells requires using the latest innovations in drilling engineering principles. These wells are more interrelated and sensitive to small changes than conventional wells. An integrated approach for both planning and execution is crucial because of the potential for risks, including high H2S percentages and drilling across high-pressure high-temperature (HP/HT) reservoirs, and all uncertainties must be properly assessed using solid engineering planning from many disciplines.

This paper describes solutions to numerous challenges in terms of both planning and execution of a high-profile well, in addition to the experience gained. With the shared experience from the lessons learned drilling the well and the offset wells worldwide, this paper proposes a way forward view of the future of drilling unconventional reservoir wells in Abu Dhabi.
Solving Field Produced Water Challenges with a Novel Guar-Based System: A Comprehensive Review of Actual Field Examples and Cost Savings Analysis
Authors: Ruyle Branden , Fragachan Francisco E
Published: November 2015

During fracturing operations, conventional and unconventional wells require from 50,000 to more than 200,000 barrels of water per well, which generates a strain on fresh water supplies. In areas where fresh water is scarce, water quality is not consistent, or delivering water to a location is logistically complex, the strain intensifies. Therefore, having capabilities to reuse produced or flowback water for fracturing applications is a cost-attractive option, especially when major savings in produced water disposal costs and reduced treatment requirements are achievable.

This paper summarizes the proven benefits of using a bi-polymer crosslinking system in environments where water quality cannot be guaranteed. In addition to the cost advantages of using a crosslink system that uses a conventional gelling agent, this paper also demonstrates the yielded cost savings per well that are achievable when reusing 100% produced and or flowback water for hydraulic fracturing operations. Produced water typically contains large amounts of dissolved monovalent and divalent salts and other types of ions. Some of the ions present in produced water interfere in the formulation of traditional crosslinking fracturing fluids and therefore create a need in certain systems to mix produced with fresh water in specific percentages. The guar-based system discussed in this paper allows for 100% produced water reuse without filtering or treatment, which is a major environmental breakthrough in fresh water preservation. The new fluid system consists of a specially formulated bio-polymer crosslinking system that is not affected by produced or inconsistent water quality typically associated with fracturing applications.

The fracturing fluid system can tolerate 100% untreated produced or flowback water with salt concentration in excess of 300,000 parts per million (ppm), between 5,000 and 30,000 ppm of divalent ions, and more than 400 ppm of boron and 185,000 ppm of chlorides. The thermal stability of the system is proven to be unaffected by bottomhole temperatures ranging from 120°F to 300°F. Rheological profiles illustrate that the fracturing fluid system yields higher viscosities compared to an equivalent, traditional borate crosslink fluid system in fresh water. Well treatment results indicate that the bi-polymer system can be accelerated or delayed with proppant-carrying/suspending properties comparable to those of a traditional crosslink system. Permeability tests demonstrate the non-damaging nature of the new system and actual field data demonstrates enhanced scale tendency reduction.

In summary, this paper comprehensively reviews the benefit of using a robust fracturing fluid that can use 100% produced water or flowback instead of fresh water for fracturing operations. The paper indicates that use of produced water or flowback for fracturing should become the norm as we move into a more environmentally friendly paradigm.
Particle Size Distribution in Casing While Drilling: A Quantitative Analysis
Authors: Velmurugan Naveen , Mathur Prakhar , Babu Vinay
Published: November 2015

In order to address various wellbore challenges, there has been improvements in methods of drilling and other wellbore activities since a long time. While the industry focuses on improvements of different methods, reducing Non Productive Time (NPT) has also become of great interest. Amongst many, one method to address the problem of drilling through fluid loss zone and to minimize casing running time and other NPT is Casing While Drilling (CwD). It is a method of drilling in which the conventional drill pipes are replces by the casing itself. During implementation of this method, there have been several observations of enhanced wellbore strength, pressure containment, better fluid loss control, etc. Plastering effect is considered to be the factor behind this, where the fine drill cuttings physically collide with the wellbore to form a stable mud cake layer that provides additional wellbore strength. Though plethora of work has been carried out, exact phenomenon of plastering effect is uncertain. Particle Size Distribution (PSD) of the drill cuttings along the wellbore is noted to play a crucial role is proper plastering effect. Authors of this paper, attempt to quantify the PSD in CwD that takes place during plastering effect. The work is expected to help in understanding the crushing effect and the background of fluid loss prevention.
An Environmentally Benign Catalytic Process Enhances in Situ the Quality of Gasoline
Authors: Kokkinos Nikolaos C. , Mitropoulos Athanassios C. , Nikolaou Nikolaos A.
Published: November 2015

In the present research work an in situ conversion process of light-light cracked naphtha (LLCN) to strong anti-knocking mixtures is proposed as a potential solution to the serious drawbacks from the use of gasoline ether oxygenates (MTBE, ETBE, TAME) from the refineries.

Aqueous biphasic Rh/TPPTS-catalysed hydroformylation reaction of olefins present in a Greek refinery naphtha cut comprises the first part of the two-step proposed process. The second part of the proposed LLCN upgrade process is the in situ hydrogenation of the produced aldehydes to the corresponding alcohols catalysed by Ru/TPPTS complex in aqueous media. Both catalytic systems of Rh/TPPTS and Ru/TPPTS were revealed as effective catalytic systems for biphasic hydroformylation and biphasic hydrogenation of complicated mixtures, respectively. The effect of the pressure, temperature and time of the reactions, as well as the influence of the L/Me molar ratio were investigated.

In the first step (hydroformylation reaction) as well as in the second step (hydrogenation reaction) the highest conversion of more than 95% of the olefins and aldehydes respectively was observed at mild conditions, at a short reaction time. The upgraded LLCN could potentially replace the harmful gasoline ether oxygenates from the refinery blended gasoline pools with an in situ and an environmentally friendly catalytic process. Therefore, the ultimate fuel will contain more oxygen, due to the producing favourable strong anti-knocking alcohol mixtures; it will have better combustion properties and bigger octane numbers.
Application of Enzyme EOR in a Mature UAE Offshore Carbonate Oil Field
Authors: Jabbar Muhammad , Azrak Omar , Berthier Maxime , Blondeau Christophe , Al-Amrie Omar
Published: November 2015

Total has been operating oil and gas production from a series of heterogeneous reservoirs offshore Abu Dhabi since 1974. One of the main oil producing reservoirs of Jurassic age has been the subject of a number of EOR studies at lab and field scale to achieve a higher ultimate recovery factor.

In 1991, TABK initiated its first gas injection EOR Pilot with full-field expansion in 1997. In 2014 a successful Chemical EOR Pilot was carried out that showed a significant drop in residual oil saturation around the target well. As all the pumping equipment was available for the Chemical EOR project a window of opportunity opened up at short notice to perform a second EOR test on other wells.

The literature has recently highlighted successful applications of a relatively cheap commercially available enzyme in mature oil wells around the world with no environmental impact. This would be the first Enzyme EOR application in the Middle Eastern carbonates and, if successful, could provide a logistically simple, cheap method for enhancing oil recovery and assist Abu Dhabi to achieve its objective of 70% recovery factors.

Although there had been no time to evaluate the product in Total’s labs it was decided to go ahead with the test anyway in the spirit of supporting ADNOC’s initiative to accelerate the application of emerging technologies. This paper discusses the design, reservoir monitoring and lessons learnt from a "Huff-n- Puff" application of Enzyme EOR.

In terms of operations, the campaign was completed successfully; it demonstrated that the application poses no risk of flow assurance or to the environment and has provided invaluable experience of incorporating an EOR Pilot in day-to-day operations. In terms of EOR effect, an increase in oil rate is observed in only one well with no significant decrease in the water cut; in addition, the increase could be equally explained by well stimulation and/or better well stability (less slugging).
24 years of successful EOR through Immiscible Tertiary Gas Injection
Authors: Madathil Asok , Azrak Omar , Pearce Adrian , Al Amrie Omar , Gunasan Erkan , Blondeau Christophe
Published: November 2015

Total has been operating oil and gas production from a series of heterogeneous reservoirs offshore Abu Dhabi since 1974. Today's world class recovery factor is due to early application of new technologies such as ESPs, gas lift, multi-lateral wells, field-wide tracer and state-of-the art reservoir monitoring and well management. But the main contributor to this high recovery factor is the application of EOR through Immiscible Tertiary Gas Injection since as early as 1991 in 2 of the main reservoirs, it resulted in a recovery factor of over 50% in one of the main reservoir; a top class achievement for a carbonate reservoir and it is still contributing to more than 15% of today's field production.

After 17 years of production, the water cut reached almost 90% in one of the main reservoir. It was imperative to improve oil mobility and recovery in the reservoir to guarantee long term production. Of the various EOR methods considered, injection of natural gas was found to be the most technically and commercially viable. Several laboratory experiments and simulation studies have been performed to confirm the benefit of gas injection. Then, 2 successful pilots in 1991 and 1993 resulted in the decision to develop the technique on a full field configuration.

The Tertiary Gas Injection has been developed on the 2 main reservoirs of the field. These 2 reservoirs have comparable OOIP but very different properties and configuration. One reservoir is 160m thick with good vertical communication and has pressure support by an active bottom aquifer. The second reservoir has 14 thin layers; each layer is 3 to 20m thick and is separated from each other by anhydrite layers with no aquifer support.

This paper will describe the practical experience of immiscible Tertiary gas injection, present the results after 24 years of injection and analyze the possible reasons for differences in performance between the wells and reservoirs. In addition, it will describe how today's strong reservoir management, integrating surface constraints, helps to optimize the production leading to a constant level of production over the past 4 years; which, for a mature oil field that normally declines at 10–15% per year, represents a great achievement.
DAS Acquisition In A Matured Field During 4D: A Challenging Initiative With Multiple Objectives
Authors: Sanghvi G. , Le-Roch J. F. , Fernagu J. , Elazabi S. , Al-Naimi A. , Parker T. , Dathan S. , Toguem E. , Lemetayer p. , Allanic Ch.
Published: November 2015

A complex carbonate oil reservoir off the coast of Qatar has been under production since 1997. The field development is based on horizontal oil producers, water injectors and the use of Electrical Submersible Pumps (ESP) as the artificial lift method. A full field 4D seismic data acquisition was undertaken in 2014 to support the future development phases. A Distributed Acoustic Sensing (DAS) acquisition was included in the 4D seismic program to capture a Vertical Seismic Profile and observe the fluid flow dynamics inside the well bore together with the reservoir inflow. The dynamics of gas fraction was imaged through a tuned operating sequence of the well. A digital movie was captured for each location in the wellbore from toe to pump intake.

The first of its kind sonic data capture involved a DAS system using fiber optics. Thanks to a permanent fiber optic into the well, the simultaneous captures of DAS system reduce the incremental cost for the DAS information.

Gas locking in the ESP is the major cause of down time and reduced ESP run life. The selected well is in an area with limited water drive. The high cost of replacing failed ESPs affects the economic limit of the well and thus reduces the recoverable oil.

The applied operational sequence successfully observed intermittent ingestion of gassy fluids into the ESP intake. This provided key information to diagnose the root cause of gas-lock.

The incident free operation has clearly imaged (filmed) the fluid dynamics of gas and liquids interacting with the ES pump intake.

How detailed the challenges of preparing and conducting this operation were overcome is described. The operational field constraints cover safety, weather constraints, unmanned well platforms, the effects of streamer shooting and simultaneous production operations. On-shore details are described in relation to unusual job planning requirements including logistics and statutory requirements.

The results show DAS images that identify the specific gas volumetric fraction of fluids all along the well and entering the pump intake. The acquisition program fully captured the development and movement of large gas bubbles towards the ESP and which subsequently develop into a gas-lock event. The sensing includes images from the drain toe, to ESP intake and onto the well head. The acquired data shows the root causes of operational difficulties particularly during an ESP restart. One can see the actual gas handling performance of the ESP system as the specific gas volume fraction at ESP intake evolves over time.

The full sequence of this DAS advanced application has fully captured a gas lock event. This brings key information to improve ESP performance in a gassy environment from the completion design and operating points of view.
Synthetic Analysis of Full-Waveform Crosshole Seismic Toward CO2EOR Monitoring in Abu Dhabi
Authors: Nakamura Yuki , Takanashi Mamoru , Elila Abusaa
Published: November 2015

This study aims at designing optimal crosshole seismic approach for CO2EOR (enhance oil recovery by CO2 injection) monitoring in Abu Dhabi. It is not easy to perform successful reservoir monitoring for carbonate reservoirs in the Middle East because rock properties may not change much associated with fluid replacement. We investigate advantage of newly available elastic full waveform inversion (FWI) for detection of CO2 flooded zones. To investigate advantage, applicability and future problem of time-lapse FWI for CO2EOR monitoring, we conducted rock physics study, elastic seismic simulation, and test application of FWI to synthetic data.

We first made realistic velocity models based on Gassmann's equation and actual well logs obtained before and after CO2 injection at carbonate reservoirs in Abu Dhabi. The in-situ light oil at the target reservoirs was replaced by CO2 (Secondary mode CO2EOR). We prepared models with different width and thickness of CO2 flooded zones and analyzed detectability of seismic waveform change. We also conducted test application of elastic full waveform inversion to synthetic data for delineation of CO2 flooded zones.

Results of the rock physics study show 1.6% decrease in P-wave velocity, little change in S-wave velocity and density associated with secondary mode CO2EOR. The small property changes are caused by the rigid rock frame and small density difference in light oil and supercritical CO2 at the reservoir condition.

Next we performed synthetic seismic analysis based on the rock property models, available crosshole seismic source and realistic well distances. Because of the small property change, seismic traveltime difference and waveform change are quite small when well distance is 116ft. When well distance is 700 ft or greater, guided waves, or trapped energy inside low velocity layers can be observed; relatively large waveform change can be observed in the guided waves due to CO2 injection. Although guided waves have not been used for reservoir monitoring, they are sensitive to small Vp and thus can be an indicator of the CO2 flooding.

The elastic FWI result for a model with well distance of 1160 ft demonstrated good representation of the differential Vp with vertical resolution of 20-30 ft and some horizontal resolution. Although we need further investigation on repeatability and signal transmittability using actual field data, our synthetic study indicates possibility of identifying layers with CO2 using guided waves and elastic FWI.
Hard Formation Durability Gains 14% Footage and Replaces 2.7 Bits Versus Offsets
Authors: Cuillier Bruno , Mangeny Aurelien , Jelly John , Ballard Brian
Published: November 2015

A specially designed diamond impregnated bit set new performance records in its initial application in a hard, abrasive Oman formation. Built for turbine drilling in the formation's sandstone-siltstones-shale, the 212.72-mm (8 3/8-in) bit drilled 588 m (1929 ft) in a single run, increasing footage drilled by 14% compared to the previous-best 8 3/8-in. run with a ROP of 2.02 m/hr (6.6 ft/hr). This performance replaced 2.7 bits through increased footage drilled and drill out capabilities. When the bit was pulled due to the BHA it was dull-graded: 3-2-WT-A-X-1-LM-BHA.

The bit developed for the Oman run was a matrix body with 16 blades. Maximum durability and performance in the high-compressive strength formation was addressed with diamond-impregnated blocks on each blade and thermo/abrasion resistant PDC cutters in the bit center. Extreme drilling conditions presented by the turbine application and formation led to an optimized impregnated segment block geometry to maximize bit durability without impacting efficiency, and a change in hydraulics to maximize cooling and cleaning of the cutting faces.

This paper is the first published examination of the diamond impregnated bit design process and resulting field experience in the Oman application. The study discusses the basis of the bit design and considerations in achieving operator objectives, including drilling as much footage as possible from 4190 m (13,743 ft) measured depth, while maintaining an average ROP of 2 to 2.5 m/hr (6.5 to 8.2 ft/hr). The authors examine the role of modeling and design software in optimizing durability and penetration rate in the hard formation, and they review enabling manufacturing and material advances.
Protecting Motor-Pipeline-Compressor from Liquid Contamination
Authors: Saez Faisa
Published: November 2015

The reliable operation of rotating machinery relies on a holistic system designs approach. Beside the intrinsic reliability of the rotating machinery, designers have to look into suction scrubber sizing and operation, piping arrangement and auxiliary systems like filtration units to assure a problem free operation. In this paper the author will discuss and present the experiences improving reliability of a Motor-Pipeline-Compressor, specifically how to prevent failures due to liquid ingress.

A field experience at a gas processing plant has forced recognition of some of the external factors affecting the reliability of centrifugal compressors with magnetic bearings. Motor-Pipeline-Compressors are widely used in the gas distribution business and has advantages over conventional compressors that the foot print is smaller, no need for mechanical seals, wide operating range and higher efficiency. However the oil & gas application has different challenges and requires a detail understanding of the dominant failure mode for a trouble free operation. In our novel application we found system defects that led to ingress ofMono Ethylene Glycol (MEG) into the compressor electric motor and magnetic bearing housing resulting in failures. These defects are:Cooling gas filtration unit without draining on secondary chamber.Suction scrubber down-comer without liquid seal.Dead leg on the suction header.Suction scrubber undersized.

This paper will present valuable information on key design features and operating practices to achieve a high reliability.
Significance of Fines and their Correlation to Reported Oil Recovery
Authors: Chakravarty Krishna Hara , Fosbøl Philip Loldrup , Thomsen Kaj
Published: November 2015

Condensation, vaporization and volumetric changes are well-studied phenomena that create differences between the properties of oil at reservoir and surface condition. But similar changes in effluent brine properties have not received the same attention. This study attempts to analyze variations in properties of the effluent brine at reservoir and surface conditions.

Various research groups have conducted water flooding experiments. Concentrations of the effluent brines have been reported. In this study speciation properties of these brines have been reanalyzed. The Extended UNIQUAC Model was used to precisely compute the brine speciation. Calculations was conducted both at surface and reservoir (pressure, temperature) conditions. And possible release of fines that remained unaccounted in previous studies was explored.

The calculation at high temperature and pressure showed that during water flooding, significant amounts of fines were released from the core plug. But with a decrease in temperature and pressure (i.e. at surface condition) these produced fines got dissolved in the effluent water. Thus the produced fines were no longer observable at room temperature. A significant increase in the solubility of anhydrite with decrease in temperature is found to be the principal reason for the dissolution of produced fines. The previously unaccounted fines were observed for the following types of experiments: Rock Type: Chalk, Limestone and DolostoneCoreplug Type: Outcrop and Reservoir CoreplugFlooding Type: Spontaneous imbibition and water flooding experimentEOR Strategy: Low salinity, Smart waterfloods and Advanced Ion ManagementRock Origin: Middle East, North Sea and United States

Furthermore a good correlation was observed between the amount of produced fines and the reported amount of oil recovery. Herein it was observed that production of fines increased significantly when the composition of injected brine was significantly altered. The interaction between the injected brines and the existing brine could have led to formation of mobile fines. This trend was found congruent with incrementing oil recovery.

The calculations show that brine speciation at reservoir condition is significantly different from that at surface conditions. During EOR waterfloods significant amounts of fines are produced which are closely correlated with the increments in oil recovery. These produced fines have previously been unaccounted for. The Extended UNIQUAC model can be used to accurately calculate the amounts of these fines.
Axial Oscillation Tool Significantly Mitigates the Vibration Level and Enhances Drilling Performance in Conjunction With Standard RSS Systems
Authors: Altamimi Ibrahim M. , Mokrani Samir , Zulkaf Ahmed H.
Published: November 2015

Since the beginning of directional drilling, static friction between the drill string and the wall of the wellbore has played a critical role in increasing the overall cost of the drilling operation. This is caused by the waste of energy due to poor weight on bit transfer or downhole tool's damages due to high vibration levels encountered.

High friction of the drill string against the wellbore has become a major concern in the process of drilling, whether it is in directional or horizontal drilling application. This source of additional torque and drag will lead to lower rates of penetration, poor tool face control, induced torsional vibration, instable drilling operation and higher rates of nonproductive rig time.

This paper presents the benefits of utilizing the axial oscillation tool in conjunction with standard RSS drive systems in directional drilling applications, whereby the mechanism of axially oscillating the BHA or drill string has substantially reduced drag and friction, resulting in improved weight transfer, more consistent torque, and therefore, more consistent reactive torque. This provides a significant reduction in stick slip vibration levels and more stable drilling operation in all modes of drilling.

With reference to the offset data, this paper also illustrates actual field runs that highlights the significant improvement in WOB transfer, ROP and torsional vibration mitigation, encountered to utilizing the Axial Oscillation Tool in conjunction with standard RSS system, which has led to more stable and cost effective drilling operation.
Better Decision Making in an Ever More Complex World
Authors: Sweatman Jill
Published: November 2015

The oil and gas industry has the opportunity to guide its collective intellects in innovative practices that grow sustainable industries. Thinking differently can further contribute to world economies and communities.

This paper is intended to stimulate debate, raise some intriguing questions and encourage in each of us the willingness to do and see things a little differently. Three key areas are discussed in the context of making better decisions in an ever more complex world: Why we need to ask the right questionsWhy we need to discipline distractionsWhy we need to create a conducive environment for decision making.

The result of multitasking, heavy multimedia usage and our world of ubiquitous distractions is having a negative impact on thinking. It takes effort to make the time to think deeply and to discipline our distractions. It is at our peril that we ignore the evidence and merely accept the velocity of our professional worlds and demanding lifestyles.

The complex and the ambiguous abound in the petroleum industry. These elements dictate a depth of thinking and intellectual dexterity that can inspire creativity and capitalize on technology. Research shows that despite sophisticated technology, the human brain remains pivotal in interpreting the practical and the nuanced. The field of neuroscience proves taking care of our most important asset, our brain, is imperative to being more effective in decision making. There are some simple actions we can all take, like walking briskly, that will improve judgment and outcomes.

Our brain may be changing due to the constant use of technology and the distractions it provides. Studies show workers are interrupted every 11 minutes, they self-interrupt 44% of the time and handle interruptions immediately 73% of the time. Such disruptions come at a high cost to ourselves and our business, especially when risk mitigation is compromised. Choosing how and when to be interrupted is necessary if we are working on an important task so that mistakes can be mitigated. We are immersed in an environment that is data-rich yet attention-impoverished. We need to be judicious about the interruptions we allow and how we deal with them. Aspects are explored with recommendations for daily practice that will improve decision making.
Development and Application of Bottomhole Pressure Intermittent Reducing Tool
Authors: Longlian Cui , Haige Wang , Fucheng Zhang , Hong Li , Guodong Ji , Lubin Zhuo
Published: November 2015

In this paper, Bottomhole pressure intermittent reducing tool (BPIRT) was introduced. The tools can enhance rate of penetration (ROP) and prolong bit footage, and ultimately improve drilling efficiency. The tool can be used in vertical wells, directional wells and horizontal wells. It can be used either with downhole motor or be used alone.

Bottomhole pressure intermittent reducing tool consists of a turbine, rotary sealing valves, and hydraulic shock damping system. The rotary sealing valves are driven by the turbine. Rotation of the rotary valves opens and closes the flow path ways and turns the continuous mud flow into periodic flow. As the periodic mud flow jets from bit nozzles, the bottomhole pressure is reduced periodically, which alter the stress state of the bottomhole rock and reduces the rock breaking energy. Hydraulic shock damping system contains a piston. The upward face of the piston is excreted by periodic mud flow, and the downward face is hydraulically connected with the annulus by 4 pores. Pressure loss of bit and hydraulic shock system provide a constant force on the piston. Typically, this force is designed to be greater than WOB with 20-30KN. The piston also provides additionally a periodically varying force (0-40KN, 10-35HZ) on bit. In normal drilling process, the piston is set at the lower restricted point. When bit jumping occurs, the tool allows the piston to move upward 5-8mm automatically, which can protect bit and drilling string.

The advantages of bottomhole pressure intermittent reducing tool as following: 1) reduce the bottomhole pressure intermittently, alter the stress state of the rock, reduce the rock breaking energy; 2) change the distribution of cuttings bed in the bottomhole, improve the cuttings upward velocity from bottomhole rock matrix, and avoid the cuttings of repeated broken; 3) provide bit additional impact energy, improve rock breaking efficiency; 4) decrease bit jumping, protect bit and drilling string; 5) stable directional drilling tool face, improve drilling efficiency.

Bottomhole pressure intermittent reducing tool has been used over 30 wells, the total footages over 35000m. The ROP is improved by 26.32%-132.18%, total 200 days drilling cycle and 30 millions drilling costs are saved. The tool has simple structure, reliable performance and long service life. Bottomhole pressure intermittent reducing tool as an effective approach to improve ROP, has great application potential in China.

As mentioned in advantages, the tool can reduce the bottomhole pressure intermittently, alter the stress state of the rock, reduce the rock breaking energy, improve the cuttings upward velocity from bottomhole rock matrix, provide bit additional impact energy and also can decrease bit jumping.
Water-oil Relative Permeability and CO2 Injection Process at Full Reservoir Conditions in an H2S Oil Bearing Carbonate Reservoir
Authors: Alawi Nidhal , Kalam Zubair , Al Sahn Hani , Bhushan Yatindra , Al-Shabibi Tariq
Published: November 2015

Assessing CO2 EOR in different areas of a field with different rock and fluid properties requires proper dynamic reservoir modelling. Good SCAL data is a key input to the dynamic model. Consequently a comprehensive SCAL program was designed for a super giant carbonate reservoir, onshore Abu Dhabi, for modeling CO2 EOR process in secondary & tertiary conditions. A careful selection of the core material based on a Petrophysical Group (PG) review was performed to make the experiments representative of key areas of the field in which CO2 flood is planned or studied.

Laboratory experiments were designed at full reservoir conditions with H2S oil bearing, and to assess possible impact of H2S on displacement efficiency. Water-oil relative permeability tests showed insignificant impact of H2S, compared with non-H2S tests on cores of different PG's. Injectivity issues and importance of brine composition on water mobility were identified. Trapped gas to water and oil were also mapped successfully.

The comparative analysis of CO2 EOR flooding scenarios using long composite cores with continuous CO2 injection and CO2 WAG were also performed. They indicate higher displacement efficiency with continuous CO2 injection. Tests were also conducted on composites with non-H2S live crude, representative of reservoir zones with little or insignificant presence of H2S.

This study indicated for the first time in the published literature, the impact of H2S in water-oil relative permeabilities of carbonates at full reservoir conditions. The gas process displacement efficiency tests also verified negligible impact of H2S (up to 12%) in CO2 EOR 1D core floods.
Improving Mega Project Economics Through the Use of Early Production
Authors: Volker James A. , Bond Adam J.
Published: November 2015

A key aspect of the Project under discussion is the use of minimal Initial Production Facilities to achieve significant early production from each of the four (4) pre-constructed artificial islands. The Initial Production Facilities leverage the utilization of the spare processing capacity on the existing adjacent satellite platforms to allow production from each of the islands to occur during the 4 year period between when the first wells are completed until completion and start-up of the Permanent Production Facilities.

The Initial Production Facilities associated with each artificial island comprise (1) the on-island Facilities that consist of wellhead flowlines, production and test headers, basic hydraulic wellhead control panels, a chemical injection skid, a hydrocarbon drain tank package, and a temporary equipment room containing distribution panels and the basic control system, (2) a riser platform containing a pig launcher, (3) a short subsea pipeline that connects the island to the existing adjacent satellite platform, and (4) the minor brownfield tie-ins on the existing adjacent satellite platform. The riser platform, short subsea pipeline, and the minor brownfield tie-ins will remain as part of the long term Permanent Production Facilities, while the on-island Initial Production Facilities are for use only during the Initial Production Phase of the Project and will be de-commissioned.

It is anticipated that the Initial Production Facilities will be in production for 4 years and during that period will achieve production from more than 60 total wells on the four (4) islands. A sequenced design and start-up approach has been utilized to align with the drilling program and to provide maximum flexibility in the final installed Initial Production Facilities at an optimum cost for each island. Wells will continue to be progressively tied into the Initial Production Facilities on each island for the life of the Facility until it is decommissioned following the start-up of the Permanent Production Facilities.

The key challenges for the Initial Production scope were (1) the high degree of simultaneous operations, (2) design and installation of the Initial Production Facilities to minimize interference with ongoing drilling operations and construction of Permanent Production Facilities, and (3) achieving safe operability while minimizing capital expenditure to maintain a low cost economic model that makes sense for an Initial Production Facility that will only be in operation for a short period of time.

Use of the Initial Production Facilities enhances the overall Project economics and also provides a valuable mitigation for any schedule delays that may be incurred in completion of the Permanent Production Facilities.
Enhancing Emergency Response Readiness and Crisis Management Effectiveness Through Predictive Advanced Modeling Tools
Authors: Scataglini L. , Buffagni M. , Petrone A. , Aiello G. , Iazeolla G. , Cassina L.
Published: November 2015

Objectives/Scope

Emergency preparedness and Crisis Management represent one of the key elements when it comes to deal with Major Accidents both for onshore and offshore facilities. Wherever process complexity (highly congested areas, simultaneous operations, presence of high H2S concentrations) and context features (desert areas, deep waters) are experienced, there is a high potential to hinder an effective response, especially in the unfortunate case that the emergency extends beyond the asset boundaries. Considerations above lead to develop an integrated approach to Emergency Response and Crisis Management, which can rely not only on management systems, plans and procedures but also on advanced tools to model critical accident scenarios. The biggest challenge in these terms is posed by the reliability of existing tools; in fact, most of the commercial package models available in the market may not be exhaustive enough to describe in detail both the near-field and far-field impact of major events like blowouts and toxic gas dispersions, taking into account the real meteocean conditions in a region of interest. The near-field results shall be used to support the emergency response processes (securing of areas, evacuation and short-term business continuity) which on the other hand need to be supported by the far-field impact assessment that provides useful info to manage potential long-term exposure of population. Yet far-field/long-term impacts to natural/societal unprotected environments cannot be exclusively evaluated with short-term modeling but needs to be treated with a dynamic approach, using advanced modeling tools to simulate the evolution of HC release or toxic dispersion events.

Method, Procedures, Process

This paper describes a number of proprietary tools developed within the Company to predict the extent of areas affected by major accidents under analysis, in particular blowouts and toxic dispersions, and their far-field effects, along with their use in real time to support the response and take immediate and appropriate actions in case of a real emergency. Benchmark with results obtained applying other commercial tools are also provided.

Results, Observation, Conclusions

The paper presents crucial elements to support an effective Emergency Response and Crisis Management both internally and externally. Integrated Environmental monitoring through the application of remote sensing satellite images, sensor and fixed station, and Web-GIS application that constitute powerful instruments to examine the composition of critical accident scenarios and their consequences in surrounding areas around industrial complexes.
Soft Sensing in Deep Wells Within Artificial Gas Lift Technology
Authors: Hammadih M. L. , Al Hosani K. , Boiko I.
Published: November 2015

Artificial gas lift technology is used in the oil industry to enhance oil recovery. Controlling this process is considered as a vital task by many researchers in the field. Solution of this problem would improve process performance and stabilize system operation. However, most of the control methodologies found in the literature and oil-field practice use only such process variables as on-surface flow and pressure measurements.

The proposed approach offers soft sensing of process variables in the well that are unavailable for measurement due to technical constraints. For instance, measuring the flow rate of gas or liquid at the depth of a few kilometres would be unfeasible, given that the existing instruments cannot endure huge pressures and high temperatures at this depth. The proposed methodology provides soft sensing of these variables by utilizing a sliding mode observer (state estimator). Sliding mode observers are widely used for acquiring good estimates of unmeasured process variables in a dynamical system. This proposed soft sensing is primarily intended for control purpose. For that reason the estimator must provide computational efficiency with acceptable rate of accuracy, since the observer must be working in real-time to be a part of the control system. By linearizing the nonlinear model of the artificial gas lift dynamics, we reduce the complexity of implementation to simple arithmetic operations that must be realized within an estimator. In this case, computational efficiency of these operations would be higher than that involving solution of complex functions and algebraic equations that are involved with the nonlinear model of the gas lift. Therefore, the proposed linear estimator is simple, higly efficient in term of computation, and it satisfies the requirement for real-time operation.

We developed a simple version of sliding mode observer through linearization principle applied in a number of points. The highly nonlinear gas lift system was linearized at different points which were selected as corresponding to different opening of the valve. This method is applicable for this scenario as the linearization of the model is valid around each point. Incorporating multiple sliding mode observers was achieved by utilizing the interpolation principle.

This novel approach was tested with the nonlinear gas lift model and simulation results was obtained for 10-point and 20-point observers. The resulting estimates tracks the actual values with insignificant error. By checking the percentage error of our estimates, we conclude that the designed observer provides good and reliable results. This would permit further enhancements in the gas lift technology with less cost, by utilizing these estimates to control the nonlinear process using some advanced control techniques such as model predictive control.
Driving Innovation With Red Zone Vehicles
Authors: Perrono Fabrice , Shah Vishal , Kannan Rajagopal , Basile Girolamo
Published: November 2015

In line with ADNOC Codes of Practice, areas where fatal H2S concentrations could exist must be classified as ‘Red Zones'. Personnel in these zones should always be under air. Al Hosn Gas facilities in the Shah field have large areas categorized as Red Zones. This presents a challenge as personnel working in these areas have to traverse long distances under air and on foot from the Red Zone perimeter to the units within, and back.

Al Hosn Gas has overcome this challenge with the development and implementation of an innovative Red Zone Vehicle. These specialized vehicles are suitable for all terrain movement and have been fitted with breathing air cylinders that can provide up to 1 hour of breathing air for up to 5 occupants, a gas monitoring screen that displays various parameters in real time, a flammable gas permissive start option and a permanent monitoring system that continuously compares the flammability of surrounding air with stored calibrated air to de-energise vehicle if a certain limit (i.e. 10% LEL) is breached, a special valve to automatically shut-off the air intake to the diesel engine if the engine accelerates rapidly in flammable atmospheres, a spark arrestor and flashing strobes & beacons which activate upon toxic or flammable gas detection.

With the implementation of the above innovation and safeguards, travel time in the plant Red Zone has been reduced by 82% (also reducing heat exposure) and up to 71% breathing air is now conserved and available to personnel in their personal SCBA sets when travelling the longest route in the Red Zone (approximately 1.5km). The breathing air system and the flammable gas protection systems are relatively inexpensive to install and are easy to upgrade individually as and when newer technologies are made available. This would not require replacement or a complete overhaul of the existing vehicle. Further, the same systems have been fitted across a wider range of industrial vehicles e.g. cranes, forklifts, trucks, etc. thus enabling an increased range of safe maintenance activities in the Red Zone.

At present, 20 existing vehicles (consisting of pick-ups, cranes, fork-lifts, cherry pickers, and a delivery truck) in the Shah Gas Plant have been successfully converted into Red Zone vehicles to allow for safe, efficient movement and smooth maintenance activities within the red zones.
Application of Flux Leakage Technique and Hydrostatic Pressure Testing to Evaluate Imperfections in Used Tubing
Authors: Majeed M Fajarul
Published: November 2015

The paper details the result of using an Integrated Inspection System that inspects used tubing by Electro Magnetic Inspection (EMI) during pull-out, and hydro-tests the string during completion. This unit was introduced and is still being used in the Bahrain field to inspect tubings during pull-out. The EMI is done using purpose built portable inspection system that will be fixed on the Rig Floor, and tubing pulled out through it. The unit consists of 3 separate chambers; a pneumatic chamber-sensor combination that detects any split or hole in the tubing, and 2 hall effect sensor chambers, one to monitor any reduction in wall thickness due to wall thinning or rod-wear, and another to detect any corrosion, transverse cuts, cracks, scales etc. The hall effect sensor detects Magnetic Flux Leakages from discontinuities. The unit is remotely operated by the Inspection Engineer from trailer, and each tubing in the string is classified based on the remaining wall thickness, as per standard API RP 5C1. The accepted tubings along with the replacements for those rejected during EMI are pressure tested during completion by the hydrotesting unit. A 70 feet long testing tool is assembled and lowered into the string using a winch and sheave arrangement, and the string is hydrotested, two tubing at a time. The testing assembly consists of packers at the top and bottom which contains pressure actuated rubber seal seals which provide an annulus that will be filled with water to test for integrity. Any drop in pressure will be recorded on the gauges, detecting any holes or splits that may be present. This unique System facilitate NDT as well as Pressure Testing of the Tubing string in one go to reduce turnaround time of the Rig significantly besides helping to save cost of tubings that could be reused. The working of each component of the integrated unit, advantages gained, and the discontinuities that were found on the tubings during inspection of several wells are discussed in detail in the paper.