bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Low-Solids Shear-Dependent Cement System Used to Cure Severe Lost Circulation while Drilling: A Case History
Authors: Urdaneta J. A. , Ravi K. , Gonzalez F. E. , Viera J. M. , Marinkovi R. Liaño , Castillo O. Pedrazas
Published: November 2015

Lost circulation in the oil industry is a recurrent and costly challenge, especially in mature fields or weak fracture-gradient zones. Incidents can result in partial to total losses in a variety of formations, including highly permeable, fractured, or cavernous types. In most cases, the first treatment options include using gel or mud pills with lost circulation materials (LCMs). However, this and other solutions currently in the market might not fix severe or total losses.

This paper presents a low-solids lost circulation solution that develops rapid gel strength when the shear rate decreases. The gel strength buildup is based on polymers and nanomaterials in the fluid system. In situations where the vein or cavernous zones are large, traditional solutions tend to be ineffective. In such cases, a shear-dependent fluid system can be used that develops gel strength as it enters the larger-flow-area lost circulation zone. This helps prevent the fluid from continuously flowing into the zone. Once the gel strength has developed, the system develops nominal compressive strength to adhere to the formation, helping prevent displacement during subsequent well operations.

A mature production field in Santa Cruz, Bolivia presented significant challenges during drilling operations. The low fracture gradient and pressurized gas formation created a narrow operational window, increasing the probability of lost circulation because of the mud density required to avoid fluid influx during drilling. In this scenario, LCMs would not stop fluid losses and were limited to pumping through the bottomhole assembly (BHA). The low-solids lost circulation solution was pumped through the drill bit. Having low solids and low rheology under shear, it can be easily pumped through the drill bit without having to pull out of the hole (POOH).

The losses were stopped by using this low-solids shear-dependent (LSSD) fluid system. Subsequently, the primary cementing was performed successfully, and effective zonal isolation was achieved. This helped eliminate non-productive time (NPT) in gas wells in Bolivia.

This paper presents a successful methodology, lessons learned, and engineering design to cure lost circulation during drilling operations by pumping a novel LSSD solution through the drill bit. The fluid system contains a low amount of solids; hence, it can be pumped through the drill bit, and the fluid characteristics are such that it will plug trouble zones effectively.
A Case History of Nitrogen Injection Monitoring in Rich Recycled Gas Condensate Reservoir, Onshore Gas Field, Abu Dhabi, UAE
Authors: Hamza Hamza M. , Al Suwaidi Mahmood , Al Jeelani Omar , Al Yafei Arafat , Basioni Mahmoud , Al Yaqoubi Khaled , Kumar Arun
Published: November 2015

A mixture of Nitrogen and hydrocarbon gas was used as a cycling gas in a large rich gas condensate reservoir to maintain reservoir pressure and thus prevent condensate drop-out due to pressure decrease below the dew point pressure. The objective of using Nitrogen gas is to partially replace some of hydrocarbon injection gas, which has a high demand for Abu Dhabi domestic consumption.

This paper presents the plan, implementation, results and analysis of an intensive reservoir monitoring program, which was conducted to monitor the Nitrogen injection and production. Additionally, the paper discusses lessons learned from the Nitrogen injection, inferences reached, and corrective actions taken.

The Nitrogen injection was started as a Mixed Case (MC) injection, where a mixture of Nitrogen (~20%) and hydrocarbon gas (~80%) was injected in all existing injectors across the entire reservoir for a period of three years. The plan was to stop the MC injection and apply a Pure Case injection (PC), which consists of injecting only pure Nitrogen in the North West area of the reservoir. The objective of the PC injection is to localize the Nitrogen injection to be able to apply Nitrogen removal technology in a specific part of the existing surface facilities whenever high Nitrogen production is reached.

Monitoring the Nitrogen production relies mainly on an intensive gas composition sampling and analysis, which have been conducted quarterly for all gas producers, in addition to other surveillance activities of the intensive reservoir monitoring program. The Nitrogen monitoring results and analysis of the MC injection showed Nitrogen breakthrough in many wells with increasing Nitrogen production trends. Different analytical techniques were applied to evaluate and predict the Nitrogen breakthroughs. Due to the unavailability of surface Nitrogen removal facilities and the increase in Nitrogen production during the MC injection, a Nitrogen risk assessment study supported a recommendation to stop the MC injection and continue cycling with dry hydrocarbon gas only as before. Also, it was decided to delay the planned PC injection for more evaluations and studies.
Acid Aided Regeneration in Amine Treating: How Effective is it?
Authors: Klinkenbijl Jeanine , Brok Theo , Critchfield Jim , Valenzuela Diego , Lee Danmi
Published: November 2015

The development of more complex energy sources is increasing to meet the growing demand for more energy. Such gas resources may be more contaminated, more complex, more costly, and contain more CO2 and H2S. At the same time, tighter environmental and product specifications necessitate smarter gas processing. This needs to be achieved by stretching current processes and developing reliable new technologies to effectively address the challenges of managing complex gases.

One area of gas processing that is well established is Acid Aided Regeneration (AAR) technology: the use of acids to reduce the regeneration steam of amine treating units has been applied since the 1960s, and is nowadays often referred to as a Formulated amine. Or, achieve a lower specification in the treated gas, due to a lower leanness in the solvent when the regeneration heat is kept constant, and thereby reduce environmental (CO2 and/or SO2) emissions.

Shell has carried out an extensive study on the use and misuse of AAR, focusing on the actual effects in operation and comparing unit performance with results of process simulation in the presence of acids in an amine solvent.

The operational effects observed are explained and general guidelines for application discussed. Although the focus of the application is on low pressure selective design (Tail Gas Treating Units), the main effects for high pressure application are also addressed in the study. In the paper the basis for the Shells AAR technology is described: Detailed analysis of process performance (both analytical solvent analysis and actual plant performance data) in aqueous amine treating units in a wide variety of applications. This gives good and consistent insight in the qualitative and quantitative results of acid addition to amine solvents and measured contaminant removal.A theoretical discussion on the acid effects in an amine solution, focusing on the energy for regeneration of the amine, as well as the option to meet a lower contaminant specification with a constant regeneration energy requirement by the addition of an acid to the amine solution.
Starving Bacteria to Stop H2S Generation
Authors: Subramanian T. S. , Adel Khalid , Awadhi Ibrahim Al
Published: November 2015

Instrument Equipment Shelters (IESs) are important control buildings within Operating Plants, housing critical Instrumentation and Control System (ICS) Panels essential for Plant operations. At one such IES building in one of the GASCO plants, frequent tripping of ICS panels was encountered, without pre-alarm indication, leading to Plant upsets and posing risk to the safe operations of the Plant. Occasionally, smell of H2S was observed. This Paper addresses the measures undertaken to identify the source of generation and diffusion of corrosive agents into the IES building and remedial measures to eliminate this chronic problem.

A detailed study was carried out which included soil and water sample collection and specialized lab testing, collection and testing of electronic cards, discussion with control system Vendors and desktop evaluation of data. Analysis of cards indicated corrosion of electronic components within the panels as the primary reason for the tripping of panels. Corrosion of electronic components was concluded to be mainly due to diffusion of H2S into the building, also as confirmed by Control System Vendors.

Ingress of corrosive agents through air inlets / doors was eliminated as a reason due to absence of any corrosive signs in HVAC air intakes and maintenance of positive air pressure within the building. Extensive investigation and testing of soil indicated presence of High concentration of Sulphate Reducing Bacteria (SRB) in the vicinity of the building. High ground water table containing sulphates, provided nutrition to SRB. The bacteria reduced the sulphates present in ground water to H2S. The H2S thus generated diffused into the building through cable entry sleeves, reaching the area beneath the false flooring on which panels were mounted, and subsequently entering the panels. Presence of conducive temperature and humidity facilitated reaction of H2S with electronic cards, thereby causing corrosion and tripping of panels. The key remedial measures recommended, (1) dewatering the surrounding area and lowering ground water levels to starve the bacteria, rendering it dormant and preventing H2S generation, and (2) sealing of cable entry sleeves to prevent any external gas ingress into the building, have been implemented, resulting in resolving the issue and maintaining the safety and integrity of plant operations.

Tripping of ICS panels due to H2S generation by bacteria present in soil is a unique phenomenon, not commonly encountered in oil and gas plants. In areas where ground water table is high, construction of buildings need to be carefully planned. Geotechnical investigation shall include testing for presence of organic content, sulphates and sulphate reducing bacteria (SRB) in soil and groundwater in addition to conventional tests.
An Ionic Liquid for Mercury Removal from Natural Gas
Authors: Abai Mahpuzah , Shariff Shahidah Mohd , Hassan Amiruddin , Cheun Kuah Yong
Published: November 2015

An increasing trend of contaminants in the oil and gas streams has been observed worldwide in the past recent years, and one of the eminent naturally occurring contaminant is mercury. Mercury has been found to be hazardous to health, safety, and environment as well as detrimental to process equipment at the oil and gas plants. The complexity in removing mercury is due to its existence in different species, mainly elemental, organo- and inorgano-mercury.

Most available technologies for mercury removal are located downstream of the acid gas removal and dehydration units and thus, leading to contamination of these units as well as mercury release to the environment. Besides its potential to be located upstream of these units to better protect the plant operations, the new technology is capable of treating the full range of mercury species by a single adsorbent or treatment step to meet the current targeted mercury level at outlet of mercury removal unit of less than 0.01 ug m-3. In addition, it can be applied to the existing mercury removal units without requiring any plant modifications or retrofitting.

A joint collaboration between PETRONAS and Queen's University Belfast has led to a development of a new technology that effectively removes mercury from oil and gas streams utilising ionic liquids. Efficient scrubbing of mercury vapour from natural gas streams has been demonstrated both in the laboratory and on an industrial scale, using chlorocuprate(II) ionic liquids impregnated on high surface area porous solid supports. This material has been tested for use within the petroleum gas production industry, and has currently been running continuously at a number of gas processing plants in Malaysia for more than three years. Since it was originally revealed, further innovative developments have been undertaken to improve its efficiency and performance for applications in liquid hydrocarbon streams. Recognitions and awards have also been received from various organisations including iChemE for the technology.

Since it was originally revealed, further innovative developments have been undertaken to improve its efficiency and performance for applications in liquid hydrocarbon streams.
Development of a Giant Carbonate Oil Field, Part 2: Migration from Pressure Maintenance Development to Sweep Oriented IOR Development
Authors: Nakashima Toshinori , Kumar Jitendra , Draoui Elyes
Published: November 2015

The studied field is a relatively homogeneous giant carbonate field composed of three stacked isolated reservoirs, having produced for nearly 50 years through a series of pressure maintenance methods. Chronologically, the implemented methods include gravity-driven dumpflood water injection, peripheral water injection and immiscible crestal gas injection. As the historical and on-going pressure maintenance oriented development is reaching its limitation in sustaining the oil production, it is necessary to move towards a sweep oriented development to further extend the plateau and increase final recovery.

A robust full field improved oil recovery (IOR) development plan is proposed with a smooth transition from pressure maintenance to sweep oriented development. The key questions to be answered in the IOR development are (a) when to migrate to sweep oriented development, (b) how to configure the pattern, (c) how to manage voidage replacement and decide the split between water and gas injection, and (d) how to resolve associated common issues with pattern water injection and crestal gas injection. The workflow includes dividing the field into three zones based on reservoir quality and current maturity to water flood. Dedicated sweep oriented strategy is defined for different zones respectively and its efficiency is evaluated through reservoir simulations by incorporating practical drilling campaign, well completion type, surface facility constraints and interference with historical development.

According to simulation results of the IOR plan, it can be concluded that the developed strategy (a) efficiently sweeps the oil without bypassed regions, effectively recovering down to residual oil saturation, (b) is quite robust with respect to the change of well count, (c) extends the plateau with efficient pressure support in the field and (d) is a reasonable approach towards yet undefined tertiary enhanced oil recovery (EOR) application.

This paper discusses the approach used to develop this IOR plan for the near and far future development of this giant carbonate field, focusing in particular on the solution of the above mentioned key questions.
Control Automation Technologies for Mega Project
Authors: Kulkarni N. V. , Musallam Khalaf
Published: November 2015

This Mega Project involves re-development of a producing oil field from 4 newly constructed aritifical islands. The new production facilities, well manifolds, pipe racks, buildings are being constructed in a modular form to reduce on site work activities. The project's main challenges included: Long field life (>30 years)Aggressive phased development scheduleLarge capacity equipment / facilitiesLimitations on fabrication yard capacitiesRemote site working conditionsBrownfield construction environment (resulting from interfaces with an early production system)
Geostatistical Modeling of Complex Deltaic Reservoirs Integrating Production Data through Optimized History Matching
Authors: Caeiro M. H. , Soares A. , Demyanov V.
Published: November 2015

Reservoir modeling involves the characterization of the internal gridded petrophysical properties distribution and the simulation of fluid production. However, a common problem associated with reservoir modeling is the highly non-linear relationship between the distribution of the petrophysical parameters (frequently with a non-stationary character) and the fluid production. To tackle this problem, this paper presents a new methodology for integrated reservoir modeling by addressing a multiscale optimization approach applied for non-stationary geostatistical history matching of complex connectivity hydrocarbon reservoirs.

The methodology comprises a two staged procedure for multiscale optimization, which includes a global optimization stage followed by a local refining stage. The former consists of optimizing the geological spatial anisotropy trend by coupling the stochastic optimization over the anisotropy multiparameter space with an image generation algorithm - direct sequential simulation with local anisotropy correction. The latter aims at refining the small scale heterogeneity by performing the local optimization based on a regional image perturbation method. The local refining optimization is achieved by taking into account the best individual well production matches.

A complex deltaic reservoir case study is presented to illustrate the applicability of the proposed methodology. An ensemble of multiple optimized history matched models is obtained respecting both the production data and the geological settings. The results show that the deltaic complex channelized pattern is well reproduced and also that the multiscale optimization improves the match between the simulated fluid profiles and the observed production data. As such, optimization is performed at multiple scales: the anisotropy trend model accounts for larger scale variability of the structures, while consecutive local refining improves convergence to dynamic response around individual wells.

The contribution of this work to petroleum technology is the implementation of a novel methodology for the reproduction of the fluids production profiles through the perturbation of the subsurface petrophysical models while honoring complex geological constrains.
By-Pass Pigging Without or With Speed Control for Gas-Condensate Pipelines
Authors: Groote G. A. , van de Camp P. B. , Veenstra P. , Broze G. , Henkes R. A.
Published: November 2015

Pigging of a multiphase (i.e. liquid/gas) pipeline can result in a large "pigged" liquid slug when a normal (i.e. non-by-pass) pig is used. This requires a large separator or slugcatcher, or otherwise accepting production deferment during pigging. These problems can be avoided by using a by-pass pig, which means that part of the gas can by-pass the pig through holes, which reduces the pig velocity and in turn it also reduces the pig-generated volume. By-pass pigging is applied more and more often, but it remains difficult to select the right by-pass opening for the initial pig run. This paper describes a simple design tool, based on steady-state hydraulic pipeline simulation results, to determine the required fixed by-pass opening. Also field experience with a speed control pig for a gas-condensate pipeline is shown (i.e. the by-pass opening is adapted along the pipeline to maintain a constant pre-set pig speed).

The by-pass pigging design tool is based on steady-state hydraulic pipeline simulations. By-pass design has two main constraints: (1) too small an opening will create a large Pig-Generated Volume (PGV), and (2) too large an opening will create too little force on the pig to overcome the wall friction. The optimum opening is when the liquid surge will be minimum, to avoid having the risk that the pig gets stuck. The main uncertainty in the prediction is the friction between the pig and the pipe wall. The simple steady state by-pass pigging design tool is validated against both dynamic simulation results and field data. The tool provides a quick method to assess the right by-pass opening without the requirement of doing an extensive dynamic simulation study.

As the pressure decreases along the pipeline, the optimum by-pass opening also varies along the pipeline; the gas velocity and therefore the pig velocity will normally increase towards the outlet of the pipeline and a larger by-pass would be preferred at this point. However, a (fixed) larger by-pass can cause difficulties when launching the pig. A speed control pig consists of a variable by-pass valve which is controlled in such a way to maintain a constant pig velocity. For example, when the by-pass opening is reduced, the pressure drop across the pig increases and therefore the pig velocity increases as well. The speed control pig has been used several times for a 70 km long gas condensate pipeline, which has successfully reduced the liquid surge into the slug catcher. Field data demonstrate that the by-pass pig speed can be maintained almost at a constant velocity, when using a speed control pig for a gas condensate pipeline.
Industrial Cybersecurity Governance
Authors: Brouwer Riemer
Published: November 2015

Information Security Governance in the Oil & Gas Industry

Cyber-attacks against a wide variety of organizations are increasing rapidly, and it seems that almost every day a new attack is making the news. The United Arab Emirates (UAE) is unfortunately no exception. Recent attacks were focusing on the financial sector through widely published compromising of ATMs and debit card systems last year. The malicious hackers vary from individuals who are looking to obtain fame in the hacker scene, to professional organizations interested in industrial espionage. To make matters worse, political motivated hacktivism is posing an increasing threat in the Middle East.

Naturally, this also affects the oil & gas industry where a similar trend is taking place. Given the importance of oil & gas to the region and the oil producing countries such as the UAE, it makes the companies involved in oil & gas an attractive target. Traditionally, these companies were mistakenly thought to be secure because the systems they deployed, Industrial Automation and Control Systems, or IACS, were air-gapped and used proprietary technologies and protocols. However, more sophisticated attacks, and enhanced connectivity between industrial and corporate networks have increased systems vulnerability.
Reservoir Modeling and Uncertainties Evaluation of a Tight Carbonate Reservoir in Offshore Abu Dhabi
Authors: Al Khoury Philippe , Sinha Amit Kumar , Gueddoud Abdel Ghani , Serry Amr Mohamed
Published: November 2015

Objective

Developing tight reservoirs is a challenge, it becomes more challenging when the reservoir is not well known and uncertainties remain in its description. This paper presents how this challenge has been addressed for an offshore tight carbonate reservoir.

Methods

A workflow is followed to obtain an optimized development plan for a tight reservoir and to evaluate the effect of uncertainties on field production. Evaluation of uncertainties uses response surface technique; it shows the most influential parameters and supports the data gathering plan to reduce uncertainties.

Results

The reservoir is generally thin with thickness variations across the field and with general thickening toward the north. The porous section of the formation is present in the northern eastern part.

This reservoir is characterized by variable porosity values and low average permeability. Well tests show a saturated oil reservoir with a gas cap.

The field development challenges are to identify a sweet area attractive for field development through representative static and dynamic models. The static model is built using log data from wells penetrations in the porous body. Very few core data are available to build correlation between porosity and permeability. The use of these data was maximized in order to populate the simulation grid with properties. Available dynamic data are used to describe pressure and fluid saturations in the porous zone where most likely fluid contacts values were evaluated and their uncertainty ranges were defined.

As a conclusion of this study, P10, P50, P90 oil production profiles were obtained and the impact of uncertainties was evaluated.

Finally with response surface technique a ranking of the uncertainties based on their effect is obtained. This ranking supports a data gathering plan and helps prioritizing actions needed to reduce the uncertainty in the estimated oil production profile.

Novel/Additive Information

Through this work, an example of an optimized development plan for a tight reservoir is presented and response surface technique is used to evaluate uncertainties effect and support the data gathering plan.
Breakthrough in Drilling Automation Saves Rig Time and Safeguards Against Human Error
Authors: Abrahamsen Egill , Bergerud Ronny , Kluge Roald , King Matthew
Published: November 2015

Objectives/Scope

The world's first deployment of an automated drilling control system on a Statoil rig in the North Sea helped the rig in saving up to 10% rig time per well through safeguarding and optimizing manual operations and through automating repetitive drilling activities such as tripping, pipe filling, connections and pump start up. Advanced modelling of well conditions, combined with closed loop control of the drilling control system provided safeguards for pressure, rotary and hoisting velocity.

Methods, Procedures, Process

The drilling instrumentation, surface- and downhole sensors are coupled with robust real-time and fully transient hydraulic, mechanical and thermodynamic models that continuously evaluate the current downhole conditions. These models determine all possible combinations of drillers' actions (string accelerations, velocities, rotation, pump start-ups and flow rates) that will cause the dynamic downhole pressure to reach or exceed upper and lower well stability- and geo-pressure prognosis. These results are actively used to safeguard both manual and automated sequences. For example should the driller attempt to pull the drill string at a velocity that would cause the downhole pressure to fall below the Pore Pressure or Collapse Pressure at any depth in the open hole section, the drilling control system will intervene and limit the upward velocity to a safe value based on the dynamic model.

Results, Observations, Conclusions

The models effectively calculated and communicated current limits to the drilling control system, allowing the control system to safeguard the well against human error during manual operations and to automate various repetitive operations. Statistics after 3 wells proved an overall time saving of 4% per well through automated repetitive sequences (such as pump start-ups and friction tests) while another 2–8% time savings per well were realized through optimized manual operations (active safeguards and safety triggers) and other improvement initiatives by the rig. Although the system was originally developed to eliminate human errors and avoid major incidents (including technical side-tracks), the daily efficiency gains indicate that the system also avoids minor issues that otherwise would have slowed down the operation without being seen as downtime or Invisible Lost Time. This indicates that the system works as intended and that the system should be able to avoid major incidents when the relevant conditions arise.

Novel/Additive Information

This paper demonstrates how automation reduces invisible lost time and allows drillers to focus on other activities while repetitive tasks are controlled by software. Furthermore, rig safety is significantly enhanced since the closed loop drilling control system prevents users from exceeding the dynamic limits calculated by the drilling control system.
Correctly Allocating Injected Gas to Targeted Zones by Integrating Data from Spectral Noise and Temperature Logs
Authors: Alabd Khaled Mohamed , Riza Faizal , Al Nuaimi Nawal , Fawzy Ahmed , Moussa Mohamed , Shnaib Fathi , El Sheshtawy Mohamed , Volkov Maxim , Nagimov Vener , Vorozhikhin Sergey
Published: November 2015

Gas Injection alone, or in Water Alternating Gas (WAG) mode to improve oil recovery (IOR) has been widely applied since the late 1950s. The incremental oil recovery attributed to IOR has been generally estimated at 5 – 10% over Secondary Recovery (water injection alone), primarily due to preferential sweep under gravitational effects. Theoretically, water and gas injection tend to have preferential sweep due to gravitational effects and formation characteristics. In practice, however, it is an operational challenge to obtain a uniform sweep across the reservoir.

One of the biggest challenges in understanding the injection behavior in gas injection wells using the conventional production logging approach is to identify the exact entry points, and to determine a representative injection profile to the actual injection volumes. Mechanical spinners provide inflow profiles within the borehole that in many cases doesn't reflect the actual gas behavior inside the addressed layers beyond the entry point.

Gas containment in the reservoir and within the targeted zone is one of the biggest hurdles. Unlike pilot projects, in full field application, channeling, cross flows, out of zone injection and premature breakthrough often occur, resulting in wasting gas, delayed response, and lower than expected recovery.

Effective reservoir management requires active & efficient reservoir surveillance in order to optimize well & reservoir performance. It is, therefore, critical to design a proactive program for data acquisition, integrating that data into a knowledge data base and to transform that knowledge into valuable information to guide future operations for remedial work, recompletion, infill drilling, and further development programs.

This paper discusses in detail how the injection profile geometry was described, and injected gas volumes were correctly allocated to targeted zones in one of the giant onshore oil fields in Abu Dhabi, UAE operated by ADCO, using integrated HPT (High Precision Temperature) and SNL (Spectral Noise Logging). Data from HPT and SNL logging package was integrated to successfully monitor water injection, identify cross-flows and locate casing leaks in injection wells for the past 2-3 years. Based on the performance, reliability, and accuracy of this advanced logging technology, ADCO has decided to use the same tools and temperature simulation to track gas injection, gas flow profile behind pipe, and to monitor any communication with any extraneous thief zones.
New Rotary Steerable Drilling System Introduction in the UAE for ADCO Delivers High DLS Capabilities While Improving ROP and Providing Extensive Formation Evaluation Data
Authors: Tipu Imran , Al Jasmi Shurooq Abdulla , Al Shamsi Juma Sulaiman , Danche Ali M. , Muhammad Javid , Nurzai Jehanzeb , Biscaro Enrico
Published: November 2015

Objective

One of the recent concepts in the industry promoted by a super major is the Limiter Re-designTMphilosophy where the performance limiters are addressed one by one to incrementally improve performance. This paper focuses on the limiter aspect of the new High build up rate RSS (HBR RSS) and the elimination of controlled ROP as a goal in a given field for a UAE operator. The paper analysis the success of redesign by comparing the controlled footage drilled before and after redesign.

Process

Drilling of directional wells is conducted by using Motor or Rotary steerable systems. Both of these systems provide directional capabilities peculiar to the system being used. BHA design defines the geometrical limits of achievable dogleg while the formation capability provides the second important element in drilling a directional well. Horizontal or highly deviated wells with high curvature provide the maximum exposure to pay zone and minimize the missed interval due to landing of well. With all else being constant a well with highest curvature during landing will have the maximum reservoir exposure as compared to other wells. This however, introduces the practical limitation of drilling wells with high dogleg, especially when in conjunction with formation evaluation LWD suites.

During drilling of challenging directional well profiles it is frequently required to control rate of penetration to achieve aggressive build-rates or compromise with the data acquisition program. This is a common practice with different rotary steerable systems in the market. As this was identified as a limiter that adversely affects ROP and geosteering capabilities a new design of RSS with higher dogleg capability was conceived, developed and deployed.

Results

The new RSS system was designed to give geometrically higher dogleg capability while still able to withstand the increased bending stresses. This high build rate RSS system was successfully able to eliminate the controlled ROP as a limiter for the given application which resulted in 39% ROP improvement. In addition the development of high build rate RSS provided multiple benefits such as: elimination of ROP and LWD limitation, increased curvature capabilities and higher reliability of RSS system with respect to high bending related issues. It also challenged the bit manufacturers to design bits capable of taking full advantage of the given RSS system.

Additive Information

This paper describes the improvement that was made in one field by eliminating a limiter. While this process was done for the given field, the applications of this process are universal. Similar issues exist in other fields around the world and additional capabilities can address limiters in ROP, Reliability or removing additional BHA Runs.
Water Injection Enhancement in Tight Carbonate Reservoir through Stim Tunnelling Stimulation Technology. A case study
Authors: Ortiz Requena Jhon Robert , Fawzy Ahmed Mohamed , Fahim Mohamed Abdulla , Mohamed Noordin Firdaus Bin , Bin Ujal Noor Nasriq
Published: November 2015

Conventional acid stimulation has been widely used in carbonate formations. When it comes to horizontal Open Hole environments, this technique has proved to fall behind the challenge of properly distributing the stimulation fluid along the bare lateral section. The non-effective fluid diversion issue is mainly associated with reservoir heterogeneities that are usually encountered in the subsurface such as fractures, permeability variations, reservoir pressure contrasts, to name a few. All this is also the cause for uneven downhole production and injection profiles, producing early breakthrough and sometimes leading to lower sweep efficiency.

ADCO (Abu Dhabi Company for Oil Onshore Operations) has been continuously encouraging implementation of new technologies aiming to maximize the effectiveness of matrix stimulation treatments. Recently, Stim Tunneling was screened for trial in a tight limestone formation in a Giant Oil Field. Stim Tunneling is a selective stimulation technique designed to enhance reservoir-wellbore contact by creating tunnels into the rock through rock dissolution.

Reservoir-A, is an Oil Carbonate Formation currently undergoing a pattern and peripheral injection scheme. The main reservoir consists of several units with subsequence layers exhibiting strong permeability variation ranging from 1 md to 10 md. Presence of fractures have been also confirmed in Bore Hole Image logs. The Stim Tunneling trial was performed in a WAG injector of an inverted 9-spot. The well was selected as a candidate for the stimulation trial seeking increased injectivity and optimized down hole injection profile.

The stimulation job design consisted of creating a series of tunnels distributed along the lateral open hole using 15% HCl acid. The performance of the well after stimulation improved remarkably with Injectivity Index increase 3 times. A case study is discussed in the paper, presenting advantages and limitations of the technology as well as lessons learned derived from the final results.
An Innovative and Interactive Tool to Optimize Well Placement and Qualify Reservoir Risks
Authors: Zhao Wenyang , Al-Neaimi Ahmed Khaleefa , Saif Omar Yousef , Al-Feky Mohamed Helmy , Ahmad Fazeel , Al-Alyak Abbas
Published: November 2015

The importance of an optimum well placement cannot be over-emphasized, because well location is one of the key factors that dominate the success of a field development plan. Well placement is a challenging and complicated process due to the complexity of reservoir, especially for a mature reservoir. The process of determining the optimized well location requires multi-disciplinary input and collaboration. In order to optimize the analysis process, this paper presents an innovative and interactive tool, which utilizes a 2-D map format to visualize the multi-disciplinary data, including reservoir management, reservoir simulation, geology, geophysics, and petrophysics. Following the analysis workflow, well target and risks can be optimized and identified by engineers through analyzing various maps, including well status map, well trajectory map, pressure map, production map, net oil thickness map, simulation confidence map, productivity index map, rock facies map, etc. The data that cannot display into map format can be accessed through links integrated in the tool.

This ADMA-OPCO offshore field is a giant field, which has been producing for almost 50 years. As a current Mid-term development plan, more than 40 new wells and 90 existing wells will be drilled or worked over from the multi-layer reservoirs. The well placement is a critical activity to achieve a sound field development plan. By utilizing the novel tool and workflow, all the planned wells have been reviewed and optimized based on current reservoir situation. Prioritization has been evaluated based on the risks and reservoir requirements. Opportunities of quick wins have been identified during the process as well. Successful completions of wells after optimization have confirmed the value of the new tool. Besides, since reservoir condition is dynamic, the tool would be utilized frequently to capture the new updated information.
The Right People in the Right Place
Authors: Al Mheiri Jawaher
Published: November 2015

The main objective of process safety competency mapping is to identify and describe the factors which are critical to the function of a particular job and work so that a match can be established between the skills required to perform a job and actual talent of job holder. Through the process of competency mapping these goals become employee performance benchmarks and help to identify training needs, to depute right kind of people for the right job that ultimately increase the productivity and performance of employees.

In order to map the competency properly, assessors shall gather a range of evidences through employee’s educational record, observations, supervisor’s reports, and questioning. As an example, key steps for competencies implementation for a specific job are divided into following four steps: Step 1: Mastery, Knowledge, Skills and Awareness competence criteria identification required for functioning of jobs and tasks – What are the refinery’s needs?Step 2: Identify Candidates and determine how those needs will be achieved either by utilizing external trainers or in house trainersStep 3: Build individual competency through their natural abilities, education, training, and experience. Formal training classes provide the basic awareness and knowledge necessary, but advanced skills require application and hands-on experienceStep 4: Measure and evaluate results, reevaluate needs

A competency matrix is developed for all level of staff to identify training needs, functional skill statement, training contents, skill area, performance and assessment criteria and relationship with other competency established to perform a job and actual talent of job holder.

Based on these results, management can carry out focused planning and develop customized training programs at individual as well as group level to achieve consistent and sustainable refinery performance.
Resolving Challenging Complexity of UnPiggable Pipelines Through Innovation
Authors: Al Dhanhani Khalfan , Al Shehhi Saif , Al Hammadi Hassan , Sayed Talal A , Al Kalllinkil Shammas
Published: November 2015

ADMA-OPCO subsea flare lines are unpiggable and exceeded the design life. These lines have never been internally inspected. To use conventional pigging and IP method of inspection on these unpiggable flare lines is high risk operations and will require long duration of pipeline shutdown.

By utilizing the new MTM technology in combination with verification technique like AUT, inspection of such pipelines are made possible, making risk management on such pipelines a reality. This technichue avoid production loss, no issues of stuck pig and modifications when performing the inspection. MTM detects magnetic anomalies caused by mechanically stressed area on a pipeline from external survey.

MTM device is attached to ROV and swim along the pipeline and collects magnetic anomalies readings; the critical locations can be detected and verified by AUT on the spot (or later). It detects metal losses and other overstress anomalies such as dents and buckles.

In combination with AUT survey and FFS/RLA, a comprehensive report is made to assess and ensuring safe operation of unpiggable piplines both subsea and underground.
Simultaneous Estimation of Relative Permeability and Capillary Pressure for PUNQ-S3 Model with A Damped Iterative Ensemble Kalman Filter Technique
Authors: Zhang Yin , Yang Daoyong , Li Heng , Patil Shirish
Published: November 2015

A damped iterative ensemble Kalman filter (IEnKF) algorithm has been proposed to estimate relative permeability and capillary pressure curves simultaneously for the PUNQ-S3 model, while its performance has been compared with that of the CMOST module. The power-law model is employed to represent the relative permeability and capillary pressure curves, while three-phase relative permeability for oil phase is determined by using the modified Stone II model. By assimilating the observed production data, the relative permeability and capillary pressure curves are inversely, automatically, and successively updated, achieving an excellent agreement with the reference cases. Not only are the associated uncertainties reduced significantly during the updating process, but also each of the updated reservoir models predicts the production profile that is in a good agreement with the reference cases. Although both the damped IEnKF and CMOST generate similar history matching results and prediction performance, the estimation accuracy of the damped IEnKF method developed in this study is generally much better than that of the CMOST. Besides, the variations in the ensemble of the updated reservoir models and production profiles of the damped IEnKF provide a robust and consistent framework for uncertainty analysis.
Mercaptans Removal for Sulphur Emission Mitigation
Authors: Cadours Renaud , Al Katheeri Sara , Al Matroushi Mohamed Salem , Ghazaly Ayman , Sayegh Salem
Published: November 2015

The GASCO industrial complex is constructed to process Natural Gas Liquids (NGL) from associated and natural gas. The liquids collected from Asab, Bu-Hasa and Habshan plants is transfer by pipeline to the Ruwais plant for further fractionation before supply to local end-users or other customers. The sweetening processes are critical steps in the GASCO complex to guarantee plant and operators safety, to comply with customers’ specification and to minimize the industrial impact on the environment. In this way, GASCO is continuously considering improvement of the processing plants, especially to minimize the sulphur emissions in the environment.

A significant part of the sulphur emission from the Ruwais plant are resulting from the operation of the molecular sieves used for mercaptans removal from propane and butane products. During regeneration step of these molecular sieves, the adsorbed mercaptans are concentrated in the regeneration gas. Combustion of this gas without treatment is resulting in a significant part of the sulphur emission.

This papers presents a detailed review of the best available technologies for mercaptans removal. Two options are discussed: treatment of the molecular sieves regeneration gas and mercaptan removal at upstream NGL extraction plants. Molecular sieves and hybrid solvent technologies are considered. The paper presents pro and cons of all the alternatives, considering the constraints of the existing GASCO industrial complex: units’ configuration, disposal or recycle of the mercaptan.

This paper presents an independent review of technologies for mercaptans removal, from the GASCO operational point of view. It summarizes the benefit and the constraints of each technology, and their impact when implemented in an existing complex.
Driving Business Results through Employee Performance
Authors: Boulting Alex
Published: November 2015

Since 2010 the ADCO EPM system has been transformed from a subjective, inconsistent, paper based system to a better defined integrated system directly linking individual to business objectives. To develop the EPM process further ADCO want to move the EPM process from being an administrative drill to a dynamic, positive experience that engages, motivates and inspires employees.

The paper concludes that: There is a high correlation between EPM effectiveness and business performanceThe quality of conversations between Appraiser and Appraisee underpins the effectiveness of the EPM system.Frequency of conversations can drive down employee satisfaction if the quality of conversations is not improved firstReporting and communication on the EPM system is a high impact low cost way driving the right behaviours that create a high performing culture
First Time in UAE - Successful Window Opening through 7in S13 CR in Qusawirah Field
Authors: Ahmad Mushtaq , ElKasrawi Ahmed
Published: November 2015

For the first time in ADCO, and the UAE, a window was opened in Super 13CR 7 inch casing in well QW-XY. Extensive pre-job planning, two way communication between ADCO and Baker Hughes, and flawless job execution were the key factors for the success which allowed ADCO to immediately reach the reservoir, saving significant time and costs versus the typical window in the 9 5/8 inch casing.

The main objective was to avoid cutting the window through the 9 5/8 inch casing to leave space for the ESP completion to be installed deeper for enhanced oil recovery and extending the well life. This also saved resources to drill 8-12/" section including OBM and 7 inch liner and its related accessories that were going to be required in case of the 9 5/8 inch casing window. The team decided to take the challenge presented in the stiffness of the Super 13CR material and the deviation at the window depth to save Rig days and resources.

This operation utilized Path-Master whip stock and Silverback milling technology to successfully open the window and drill the required rat-hole in one trip. Another reaming trip was carried out to ensure seamless reentry with the drilling BHA later on. Teamwork and cooperation are the keywords that made this operation possible; with Baker Hughes technology and ADCO's innovation.

This paper describes the first ever window opeing thorugh 7in S13CR in the UAE. This includes planning, risk assessment, the challeges, procedures and the conclusion. A detailed cost-benefit analysis is presented between 9-5/8" convetional window opeing compared with 7in window.