bluuebunny/crossref_metadata_2025 huggingface dataset:
Selection and Deployment of Downhole Self-Equalizing Sub-Surface Safety Valves over Non-Equalizing Sub-Surface Safety Valves in Deepwater Wells
Authors: Singh Dheeraj
Published: November 2017

An operator in the deep-water block planned to drill additional wells targeted into the gas cap of depleted reservoirs via sidetrack operations. Historically in this field, as part of the completion systems design, the use of non-equalizing safety valves were selected for the applications largely due to concerns associated with integrity of the well completions over the life of the well.

The surface controlled subsurface safety valves (SCSSV) were set at depths in the wellbore below the hydrate stability region, to mitigate concerns of hydrates around the safety valve, as well as slam closure specifications required for high velocity flow rates of hydrocarbon fluids (oil/gas) through the safety valve. Since the SCSSVs were non-equalizing, in order to open the valve, hydraulic pressure typically generated by a liquid column, is applied to equalize across the valve’s closure mechanism prior to opening with the control line fluid.

During completions and interventions operations, the liquid column to equalize the safety valve at the subsea safety valve depths of 1000 meters from the rig rotary table and use of 9 5/8" 53.5 ppf landing strings, could be upwards of 300 bbl of liquid. This presents a problem when the valve is equalized in a gas well environment because the liquid is expected to drop into the wellbore once the safety valve is equalized and fully opened. In the case of depleted gas reservoirs, there is an increased risk against the gas reservoir naturally flowing and cleaning up this liquid volume from the well, and is further compounded with high flow line pressures, resulting in an inability to produce the well. After careful consideration, the above risks were identified, and a possible solution of using a self-equalizing SCSSV to mitigate the need to use a liquid column to equalize the system and enhance the natural ability of the well to flow was advised.

Selection of Downhole Safety Valves in Deepwater applications is most significant aspect of well completion design; especially in depleted reservoirs. An operator should judiciously select from Self-Equalizing and Non-Equalizing Safety Valves available in the market.
Frac Modeling: Integrating Proppant Transport with Geomechanical Properties for Long-Term Results in Liquids-Rich Plays
Authors: Yusuf Ahmed , Bilgesu Ilkin
Published: November 2017

Several techniques for hydraulically fracturing design were conducted in the liquid-rich Eagle Ford developments. This study shows that different results were observed due to the variation of geomechanical stresses of the rock across a play and reservoir properties. An optimum treatment for a liquids-rich objective is much different than that for a gas shale primarily due to the multiphase flow and higher viscosities encountered.

This paper presents a treatment workflow that has been used with liquids-rich window of the Eagle Ford Shale. Review and integration of data from multiple sets across the play were used as input to a 3D hydraulic fracture simulator to model key fracture parameters which control production enhancement. These results were then used with production analysis and forecast, well optimization, and economic model to compare which treatment designs yield the best placement of proppant to deliver both high initial production and long term ultimate recoveries.

A key focus for this workflow was to maximize proppant transport to achieve a continuous - optimum conductive - fracture half length. Often, due to the complexity of unconventional deposition, it is difficult to maintain complete connectivity of a proppant pack back to the wellbore. As a result, much of the potential of the fracture network is lost. Understanding the interaction of a hydraulic fracture and the rock fabric helps with the design of this behavior to achieve best results. These results can then be used for determining optimum well spacing to effectively develop a selected reservoir acreage.

Currently, there are numerous wells and over two years of production history in much of the Eagle Ford. Comparison of these production results demonstrate the importance of employing a diligent workflow to integrate the sciences so that a proper understanding and application of hydraulic fracturing modeling can be achieved.
Guideline for Development of CO2 Capture, Transport and EOR Integrated System for UAE
Authors: Singh Prachi , Geuzebroek Frank
Published: November 2017

Based on ADNOC 2030 vision and several initiatives taken in UAE to reduce carbon emission, it is essential to look into the suitiable options for CO2 capture and its utilization with a focus on EOR application in UAE. Hence, a high-level roadmap for carbon capture and utilization (CCU) project is proposed in this work. This gives guidelines and directions for activities required to develop successful future CCU projects in UAE. It is a crucial first step to evaluate the potential CO2 emission sources suitable for CO2 capture technology i.e. single point sources in UAE. Power generation followed by cement industry are the largest CO2 emission sectors in terms of CO2 volumes followed by oil and gas industry. This work indicates that source to sink matching is essential at this stage to develop a suitable CCU infrastructure. Moreover, further investments in research and development are required to develop low-cost CO2 capture technologies suitable for low CO2 concentration emission sources such as natural gas fired power generation.
Impact of Near-Surface Heterogeneity on Seismic Reservoir Monitoring Simulated Using the Real Field Data in Abu Dhabi
Authors: Nakatsukasa M. , Nakamura Y. , Kato A. , Hagiwara H. , Grandi A. , Elila A. K.
Published: November 2017

Time-lapse (4D) seismic in onshore Abu Dhabi is extremely challenging. Velocity changes due to fluid displacement are very small: time-lapse P-wave velocity changes after 3 years of CO2 injection are estimated −2% around injection wells. 4D noises are problematic too. Near surface heterogeneities hereafter investigated represent the most dramatic source of non-repeatable noise.

To investigate the behavior of non-repeatable noises seismic modeling has been performed. Surface and VSP seismic were both generated using a 2D Finite-Difference Time-Domain (FDTD) method. Expected 4D effects were modeled through simulation results before and after injection. P- and S-wave velocity, and density model within the reservoir, overburden, and near surface are derived from reservoir simulation models, cores, well log data, and uphole surveys. Time-lapse perturbations are added to near surface intervals to take into account possible variations.

Surface seismic gathers show predominant elastic scattering, hence near surface non-repeatable noises overwhelm time-lapse (4D) changes. On the other hand, VSP gathers exhibit clearer reservoir reflections and time-lapse. After reverse time migration 4D processing, VSP data indicate the main potential to detect 4D changes. Source and receiver positioning errors are also included, as such errors usually create strong bias. This study confirms that source position repeatability is critical and therefore a permanent seismic monitoring system would be required for successful detection in onshore Abu Dhabi.
Identification of a Cost Competitive Development for a High-Pressure, High-H2S Richest Gas Condensate Carbonate Reservoir in the Sultanate of Oman
Authors: Mourad Ahmed , Calvert Stephen , Djermouni Karima , Hattali Ahmed , Nabhani Abdullah , Noirot Jean-Christophe , Naamani Ali
Published: November 2017

The development of high rich gas condensate carbonate reservoirs remains very challenging for the industry especially when the fluid is near critical conditions Ref (5). In some cases, the presence of high pressure, high H2S and CO2 in these reservoirs adds further to the complexity. In these circumstances, it is very important that detailed field development screening and planning are conducted to identify effective and cost competitive development solutions early in a fields life, preferably before starting commercial production.

A compositional simulation model of the richest gas condensate carbonate reservoir in the south of the Sultanate of Oman has been built to identify and select an optimum development scheme for the field. A representative fluid model based on Equation of State (EOS) is used for predicting the complex and dynamic phase behavior of the reservoir hydrocarbons. The performed simulations confirm that achieving maximum ultimate recovery for both gas and condensate is very challenging in this type of reservoir. The most effective recognized technique for maximizing the condensate recovery is gas recycling for pressure maintenance. A feasibility comparison was performed between no gas injection (depletion production), partial pressure maintenance (10 and 20 years of gas re-injection) and full pressure maintenance (long term gas re-injection). In addition, different sensitivities were considered to come up with an optimum development based on key economic indicators: Net Present Value (NPV); Value Investment Ratio (VIR) and Unit Technical Cost (UTC).

On the basis of the study results, it clearly appears that a gas recycling development is the best option to significantly increase condensate recovery (up to doubling it). However, economical evaluations show that a gas depletion development leads to higher NPV and VIR, mainly due to the early production of gas and the expected high surface facilities Capital Expenditure (CAPEX) associated with gas recycling in this type of high pressure, high souring, and very rich gas condensate carbonate reservoir.

This paper highlights and summarizes the challenges faced during the identification of a cost competitive development in high-pressure, highly sour, very rich gas condensate carbonate reservoirs.
Successful Recovery and Stimulation of a Long HP/HT Horizontal Well in One Intervention: A Case History of Acid Fracturing and New Generation of Diversion Systems Combination, Middle Marrat Carbonate Formation
Authors: Sierra Leopoldo , Alboueshi Alaa Eldine , Elmofti Mohamed , Eid Walid , Sadeddin Salma , Allam Ahmed , Al Othman Mohamed , Ahmed Zamzam , Fidan Erkan , Al-Zaidani Ibrahim , Nilotpaul Neoq , Ashkanani Meshari , Buhamad Ali , Al-Dousari Mohammed Abdullah , Ahmed Abdul-Samad Mohammed , Al-Matrouk Yousef
Published: November 2017

The proper fracture stimulation of high-pressure/high-temperature (HP/HT) carbonate formations completed with horizontal wellbores is a challenging task for any operator or service company, particularly because of concerns associated with HP/HT, acid reactivity, completion and production equipment corrosion, and acid distribution. The case history presented in this paper describes the performance of an acid fracture intervention in a HP/HT well where, because of a number of problems encountered during the well construction stage, this intervention was the last procedure considered to evaluate the productivity of a Marrat formation well.

In view of the stimulation challenges encountered, the architecture of the wellbore, and the intervention stimulation requirement to evaluate the productivity of the horizontal well completed in the Marrat formation, it was necessary to change the proppant fracture stimulation technique originally planned. Instead, it was decided that a selective acid fracture stimulation would be performed in the prospective part of the horizontal section where three long perforation clusters had been placed. Acidizing fracture stimulation was performed in one intervention using a next-generation liquid and soluble solid diversion system that enabled the generation of one selective fracture per perforation cluster.

The planned acidizing fracture stimulation process was implemented properly in the field in accordance with the design constraints. The reactive fluid system diversion and the generation of a new fracture when the diversion system reached the perforation were clearly observed. The post-acid fractured well productivity index (PI) showed the high quality of the stimulation performed in a challenging environment, demonstrating the effectiveness of the new diversion system for creating selective fractures in a horizontal wellbore with multiple perforation clusters.

Considering the well's architecture, HP/HT nature, and single intervention requirement, the case study documented in the paper can be helpful in the decision-making process when selecting a proper stimulation technique for challenging conditions. The effectiveness of the new diversion systems is also discussed.
Selection of Optimized Gas Processing and Sulphur Recovery Technology Line Ups for Different Feed Gases
Authors: Srinivasan Rajiv , Sonawane Nilesh
Published: November 2017

Petroleum Development Oman (PDO) is developing sour gas fields across the country in order to meet the gas demand to sustain industrial growth in Sultanate of Oman.

The projects involve development of high pressure, high temperature sour associated gas reservoirs with oil rims as well as non-associated gas reservoirs. The reservoirs are located at a depth of around 3 - 5 km. The sour gas produced contain significant amounts of H2S and CO2 in addition to other contaminants such as mercaptans, carbonyl sulphide (COS) and carbon disulphide (CS2).

For a couple of projects, in the absence of a suitable sink for the acid gas and due to HSE risks associated with high pressure acid gas injection (> 400 bar), sulphur recovery has been selected as the acid gas processing route. The various sour gas fields being developed have different levels of contaminants whereby employing a standardized process line up of gas treatment and sulphur recovery technologies may not be either technically feasible or economically optimum.

Among the many engineering challenges associated with any sour gas field development, the combination of Sultanate of Oman's ultra-high sulphur-recovery efficiency (SRE) specification of 99.9%, and the very stringent SO2 emission specification of 35 mg/Nm3, poses a steep challenge and pushes established technological boundaries. Further, if the sweet gas produced will have to be exported to the Government Gas network, it has to meet a tight total sulphur specification of < 5 ppmv. In case the gas is to be used for internal consumption within PDO, the total sulphur specification is < 100 ppmv.

The combination of these regulatory requirements makes the design of the gas treatment and sulphur recovery facilities extremely challenging. It is clear that best-in-class solutions would be necessary for the projects to comply with the standards.

The concentration of different contaminants in the feed gas and the selection of the sweet gas export route dictate the choice of optimum gas processing and sulphur recovery technologies and their integration. For the projects under consideration, PDO has evaluated a wide portfolio of gas processing and sulphur recovery technologies and has selected process line ups comprising of a fit for purpose combination of technologies.

An integrated approach ensured that interfaces between the different units were efficiently managed and the configuration was fully optimized thereby enhancing energy efficiency.

This paper presents the selection of the optimized combination of gas processing and sulphur recovery technologies that cater for different feed gas contaminant concentrations and yet comply with the regulatory requirements.
Key Learnings from Re-Development Activity and Waterflood EOR of Mature Brown Field: Heterogeneous Compartmentalized Reservoir Case Study, Western Desert, Egypt
Authors: El-Bagoury M. A. , Fahmy M. , Kamal M. , Saad A. , VanHeeswijk V. , Kharboutly R.
Published: November 2017

In this research an integrated reservoir study was performed on one of the successful water flood projects in Bapetco; The NE-Abu Gharadig-1 field which passes through a several phases of development started with appraisal and delineation, initial development (fast track), re-development phase and last phase of reservoir simulation. The conducted field re-development activities increase the EOR expectations and tackle the remaining reservoir potential.

Until the moment 58 wells were drilled in this field 29 oil producer, 26 water injector and 3 water source wells. Different accumulations and segments were interpreted; these segments did not indicate full communication as the thinly bedded Bahariya sequence of 200 meter thickness shows a wide range of reservoir properties and heterogeneity including porosity, permeability and hydrocarbon saturation. Geo-cellar modeling approach was beneficial in this field in order to link the static and dynamic data until reaching a certain level of match and harmony.

Twelve productive zones were interrelated through an attempt to construct structural and stratigraphic facies distribution framework guided by cores and BHI. The 3D geo-cellar modeling was applied to the probable cases and prospective blocks. Petrel data analysis tool was activated in order to control the probability distribution in property modeling. Further reservoir simulator was used to incorporate the engineering data as pressure and production; therefore optimal development strategies are aligned with the findings and forecasts of each reservoir sector. The results indicate a massive variation in vertical and lateral OIIP distribution and URF which is ranging from 16 % to 40 % on the best chances; this variance controlled by the reservoir architecture, compartmentalization, reservoir rock types, relative permeability curves, minor faults and fractures associated with different stress regimes.

The WF pattern fitting and placement were optimized to overcome the geological constrains by additional two phases of infill wells. The results provides a robust reserves stair case through a multi-phases of development and modeling to increase the field production life, improve pattern flood, optimize enhanced recovery and smooth operation.
A New Shortcut Workflow in Flexible Reservoir Modeling: Introducing Structural Features without Re-Gridding
Authors: Martínez Alejandro Rodríguez , Frambati Stefano
Published: November 2017

Current reservoir modeling workflows are very rigid, since any modification to the understanding of the underlying structural model often requires a complete regeneration of the reservoir grid, with the associated costs, delays and incompatibilities with past calculations. We propose a novel workflow for structural features modeling, allowing the introduction of faults and other structural and non-structural features in any kind of simulation grid without modifying it. A new tool, capable of implementing the proposed workflow, is presented along with several real-world case studies that prove the advantages of the new workflow.
Workflow For Multi-Scale Data Integration in Onshore CO2 EOR Project
Authors: Igarashi Akira , Shimokata Noriaki
Published: November 2017

The planning stage of CO2 EOR evaluation of remaining oil volume including immovable oil is one of the most important work because of its significant impact on field performance and project economics. However, planning becomes very challenging when the concerned field is a legacy field where historical data are insufficient unless reliable data were later supplemented. This paper describes how to evaluate CO2 EOR project for a legacy field with insufficient historical data.

To estimate the remaining movable/immovable oil volume in the field, the following multi-scale data were reviewed. Varying results were captured by review as shown below; SCAL (Special Core AnaLysis) ReviewSWCTT (Single Well Chemical Tracer Test)Material Balance CalculationCO2 Pilot Test

Residual oil saturation measured in-situ by SWCTT in wellbore scale was cross-checked with past SCAL results in core scale. Remaining oil saturation was estimated by utilizing a full-field reservoir model with material balance check. CO2 Pilot Test confirmed oil saturation decrease after CO2 injection in well-logging scale. As a result, uncertainties were identified in the residual and remaining oil saturation.

A Type Curve that represents production performance of a certain area/zone was established based on numerical pattern model incorporating reservoir characteristics including the above oil saturation profiles. By superposing the Type Curves as per the pattern development schedule, total field production profile was predicted. Incorporating the above uncertainties of residual/remaining oil saturations, several Type Curves were prepared.

Additionally, a reservoir simulation study indicates that the WAG scheme, for instances WAG ratio and slug size, would impact on an incremental oil recovery. Accordingly, an optimization study of the WAG scheme is currently in progress and this will impact on oil recovery.

In summary, oil recovery estimate for this particular legacy oil field required detailed data reviews mainly due to uncertainties of the volume of remaining oil. CO2 Pilot Test results provided direct evaluation of EOR effectiveness and supported oil saturation change with CO2 injection. Residual/remaining oil saturation need to be revisited with the additional information acquired during project execution stage to improve the accuracy of estimated incremental oil recovery.
Integrated Formation Evaluation Applications in Tarmat Identification, Well Placement, and ICD Completions Design Using Source-Less NMR Technology – A Case Study from a Middle East Jurassic Reservoir
Authors: Anurag Atul , Mishra Anoop , Mustafa Hammad , Hosany Khalil Ibrahim , AL-Jefri Ghassan M. , Chitre Sunil , Javid Khalid , Smart Charles , Bhatt Pranjal , Soliman Ahmed , Kieduppatum Piyanuch , Potshangbam Sanathoi
Published: November 2017

This paper presents the successful integration of an advanced nuclear magnetic resonance (NMR) log, a source-less technology, with core data and other openhole logs to resolve the challenges of reservoir characterization (including identification of tar mat) and to place the wells in targeted reservoirs zones. This enabled subsequent inflow control devices (ICD) completion design for optimal production in these complex carbonate Jurassic reservoirs.

A comprehensive suite of advanced logs, conventional logs and core data were used. The wireline suite covered conventional (resistivity-density-neutron-gamma ray-acoustic) and advanced (NMR-elemental spectroscopy-image) technologies in one of the pilot wells. In another calibration well, data gathering was achieved with wireline (resistivity-density-neutron-gamma ray) and LWD NMR to log the same reservoirs. Integration using these conventional logs, advanced logs and core data established the correlations to derive permeability in this complex carbonate Jurassic reservoirs. From these study wells, a correlation was established between the NMR porosity, density/neutron porosity and core porosity to enhance confidence on NMR-measured porosity. The NMR permeability index was calibrated using parameters that were developed by integrating NMR results with the core data. This permeability relationship (core and NMR) was applied in all lateral wells with LWD NMR results that targeted the same reservoirs in the field. For delineating the tar mat interval, a combination of NMR, density and resistivity measurements was used.

The LWD NMR results provided real-time reservoir characterization with rock quality (porosity distribution, permeability) that helped in ICD completion design and enhanced well placement. This approach and technology also enabled substantial rig time savings and reduced HSE risks.

This approach demonstrates strong benefits of data integration and proven LWD NMR source-less and lithology-independent technology, in addition to the resistivity and gamma ray, as the preferred solution for advanced reservoir characterization, ICD completion design, and enhanced well placement in complex carbonate reservoirs.

The solution for reservoir characterization enabled confident decisions on ICD completion design and enhanced well placement by implementation of source-less technology, eliminating the risks of using radioactive source-based technology.
Saturation Modelling Under Complex Fluid Fill History - Drainage and Imbibition
Authors: Xian H. , Beugelsdijk L. , Kohli A. , Fokkema E. , Cense A.
Published: November 2017

A saturation modelling approach is presented for fields and reservoirs under complex hydrocarbon charging history. The model resolves saturation-height functions for the primary drainage, imbibition and secondary drainage equilibriums. As part of the approach, a method of evaluating the residual hydrocarbon saturation below the initial free water level is proposed.

The developed theory is based on the principle of capillary pressure-saturation hysteresis on the drainage-imbibition process in a water wet system. In this study, saturation-height models have been built with parameters determined by fitting the SCAL capillary pressure drainage and imbibition measurements. A novel approach is presented for evaluating the residual hydrocarbon saturation in relationship with the initial hydrocarbon saturation, integrating both core measurements and log saturation with a pressure depletion factor. An integrated process of modelling a primary drainage-imbibition-secondary drainage cycle based on both SCAL data and well logs is provided.

Parameters for the primary drainage, imbibition and secondary drainage curves are resolved respectively. Large variety of SCAL capillary pressure data and well logs from The Netherlands and North Sea fields are used in the study. The modified van Genuchten (VG) equation provides the best fit with the core imbibition curves and has subsequently been implemented for the reservoir and field models. Examples and case studies have successfully demonstrated the modelling of the hydrocarbon saturation under imbibition and secondary drainage equilibrium, which in extreme cases could co-exist in a field. The results of the saturation-height model in a 3D reservoir model using the fluid contacts information from log data, pressure and seismic are seen to very well align with the saturation log in wells. The residual gas saturation model built from the core measurements is compared with the in-situ residual gas saturation observations from logs. The mobility of residual or trapped gas at reservoir conditions is also discussed. From the examples and case studies discussed, it can be concluded that this new approach for hydrocarbon saturation modelling for fields under a complex fluid fill history of imbibition and/or secondary drainage equilibriums is robust and can be implemented in 3D static model and considered having high potential for dynamic reservoir simulation.
Implementation of Dispersed Gas Model for Kick Tolerance Analysis of an HPHT Exploration Well in Norway
Authors: Karahasan K. , Oyovwevotu J. S. , Vielma W. E.
Published: November 2017

Minimum requirements for kick tolerance (KT) in Maersk Oil corporate standards drove implementation of analysis using a dispersed model instead of a single-bubble model to achieve more realistic KT values for a planned high pressure and high temperature (HPHT) exploration well with oil-based drilling fluids.

The large uncertainty bands of predicted pore and fracture pressures in an HPHT exploration well offshore Norway had driven the casing design, which had very narrow margins and little flexibility in setting depths for the casing strings. KT analysis using a single-bubble model indicated allowable kick volumes of less than the required 50bbl minimum. To comply fully with the 50bbl KT, additional casing strings would be required, with several liners and/or unconventional casing sizes, adding further complexity, cost, and risk to the well and the operations. The development of a well control bridging document, including HPHT procedures, competency assurance of the crew, and use of real-time pore pressure prediction service was considered inadequate to fully manage the associated well control risk.

The benefit of accepting the less than 50bbl KT would be to enable drilling of the HPHT exploration well with the planned five-string casing design, which was already more robust than in most of the offset wells, which utilized a four-string design. With the five-casing-string approach, there is little room for a contingency casing/liner string without possible compromise of some of the well objectives.

An internal dispensation process was initiated due to the noncompliance with Maersk Oil corporate standards. To secure dispensation from such corporate standards, transient drilling modeling software was used to calculate updated KT on the basis of the dispersed kick (gas) model. In addition, a plan was put in place to update the well model and recalculate KT using real-time well information.

This case history presents the story of KT analysis of the subject well, including transient drilling modeling to investigate the sensitivity of input parameters. Furthermore, a description of the software's use to assure safe drilling operations is discussed. Lessons learnt from use of this software during planning and well construction will also be discussed.
Transpressional and Transtensional Structural Patterns in Abu Dhabi Fields, UAE
Authors: Noufal Abdelwahab , Obaid Khalid
Published: November 2017

Abu Dhabi fields profitable development starts with understanding structural framework and styles kinematically and dynamically in the context of regional and local exploration resource potential evaluation. This enables to determine and predict the structural controls on deposition and understand the nature and development of trap styles.

The fault systems in Abu Dhabi fields investigating the different stages of geometrically, kinematically and dynamically development of strike-slip basins. The seismically mapped stratigraphic succession starts with the Permian, that showing fault systems characterized by Late Mesozoic transpressional wrench tectonics. Abu Dhabi mature basins provide important information on the temporal and spatial changes in sediment source, depositional systems, and uplift history of Abu Dhabi fields. A gap is existing between the faults systems interpreted on the magnetic maps that showing NE lineaments and the Permian-Tertiary succession with main faults tending due NW. Below the deeper Permian interpreted horizons and up to the basement is not clear in Abu Dhabi, as the seismic is not cover the deeper section. Therefore, a tectonic model is required that captured the unknown using the known faulting relations with the depositional and deformed rock units.

This work is a multi-disciplined investigation of the complex spatial and temporal relationships between facies distribution and faulting, which exist during basin evolution in a tectonically active intracontinental setting. This exciting field-based study will integrate structural mapping, structural techniques, and seismic interpretation to examine the diverse origins of strike-slip related basins in the UAE. The aim of the fieldwork was to gain a three-dimensional picture for the tectonic system that has operated in Abu Dhabi basins through time, and to understand the interplay between faulting, basin margin deformation, facies distribution, architecture, and adjacent mountain building.

Kinematic analysis of faults for stress determination was carried out on Permian up to Tertiary rocks, which revealed various transtensional and/or transpressional regime. Abu Dhabi deformation was segregated into two coeval distinctive states of stress. The Permian-Cretaceous state of stress was compressional, with σ1 oriented in a NW-SE direction and changed by the Tertiary to be due NE.

This paper address generating reliable distributions of the deformation zones predictions that can impact the reservoir parameters geodynamically within onshore/offshore Abu Dhabi successions where the development induced modifications and their effects on reservoir permeability can be understood and managed.
Mineralogy and Geomechanical Analysis for Hydraulic Fracturing: An Integrated Approach to Assess Rock Fracability in Sandstone Reservoirs
Authors: Alsaif Noor A. , Hage Ahmad R. , Hamam Hassan H.
Published: November 2017

A comprehensive integrated methodology is presented that assesses rock hydraulic fracability using rock geomechanics, mineralogy, and chemical compositions. This petrophysical multi-min based approach utilizes sonic and density log data to relate mineralogy and geomechanics to rock stiffness and its susceptibility to fracture.

Rock fracability is assessed in terms of compressional and shear transit times from borehole acoustic logging. These transit times are used to calculate Poisson's ratio and Young's modulus that provide an indication of the tendency of a rock to fracture while preserving the opening of the fracture. The lower the Poisson's ratio, the more brittle is the rock and the higher the value of Young's modulus. Brittleness index and fracability index are introduced to predict fracable rocks; sands with a brittleness index of 50 and higher and fracability index above 0 and less than 1 are fracable candidates.

This geomechanical analysis is combined with rock mineralogy to make conclusive predictions about rock fracability. Rocks rich in silicates and sufficient clay volumes exhibit high rock fracability while ductile rocks negatively impact fracability. The success of the hydraulic fracturing jobs was observed to be directly related to rock mineralogy. The mineralogy groups for the wells in study were silicates (Quartz and Orthoclase) and clays (Illite, Kaolinite, and Chlorite). Quartz associated with sufficient Illite volumes promoted fracability. However, high contents of Kaolinite led to unfavorable results, whereas small quantities of Chlorite positively impacted fracability and promoted well deliverability. The integrated approach showed good predictability and consistency of rock fracability with a certain degree of error (within 10%).

This approach has been applied successfully on different sands with a wide variation in chemical compositions. It can predict wells with the highest success rate of the fracturing operation, save the injectivity test, minimize the fracturing costs and optimize the economics of tight reservoirs.
Main Oil Line Pump Seal Failure Prevention; Advanced Simulation and Case Study
Authors: Khalaf A. M. , Al Omari A. M. , Al-Sherif A. H. , Toubar A. , Barsoum I. , Karrech A.
Published: November 2017

Main oil line (MOL) pumps are responsible to deliver the produced oil from an oilfield to a processing and storage facility where oil is exported through a loading station. MOL pumps failure is considered disastrous due to the fact that it introduces a safety hazard and leads to business and operational interruption. This paper studies a failure prevention approach of MOL pump bearing isolator/seal using computational mechanics simulation to predict the failure and maximize pump reliability.

This research conducted is a case study of failed MOL pump bearing isolator, made of Teflon, which occurred during the pump's Factory Acceptance Test (FAT). The pump capacity is in the magnitude of 250,000 barrel/day. A Finite Element (FE) axisymmetric coupled steady state temperature-displacement model of the bearing isolator was developed. The FE model mimics the actual pump operating conditions to simulate the seal performance. FE results of two different materials, Teflon and Bearing Bronze, were assessed and compared against seal behavior during pump testing. Recommendations to prevent future on-site failures were made and executed based on FE outcomes.

During MOL pump FAT, a Teflon bearing isolator repeatedly failed while running under its normal operating conditions. It is found that the isolator's rotating part is deflecting during operation due to the effect of centrifugal force and thermal growth. This deflection causes the rotating part outer diameter to contact, radially, with the stationary part leading to frictional heat generation and subsequent component rupture. The built FE model was utilized to analyze the failure pattern. The FE model predictions were able to identify the exact location of the failure, under the actual operating speed and temperature. Excellent agreement between FE analysis results and actual failure was observed. In order to prevent this failure from occuring at site, change of material was proposed to improve the seal performance. Another FE analysis was built utilizing Bearing Bronze material, which is a commonly used material for this application, to examine the bearing seal integrity under the same operating conditions. FE results showed that Bronze is able to perform without failure due to relatively negligible deformations. Bronze material seal was then adopted and tested with no failure. The risk of Teflon seal premature failure was hence eliminated.

Bearing isolator selection criteria are not sufficiently covered in any international standard. Operating companies depend solely on manufacturer recommendations. Bearing seal failure due to pump rotation can be analyzed only with advanced engineering simulation due to its dynamic behavior and access limitations. The outcomes of this assessment were able to predict/prevent MOL pump bearing seal failure. This will allow taking action before failure takes place, and provide a material selection guideline for such machine element.
State of the Art Biodegradable Diversion Technology Applied on Tight Carbonates Reservoir Leads to Maximized Production
Authors: Gonzalez David , Ulloa Joel , Safari Reza , Al-Rawi Aws , Babey Andrew
Published: November 2017

The need for diversion in acid stimulation jobs has become a necessity with which we cannot dispense. Various diverting agents are available commercially and can be used effectively when there is a low to moderate permeability contrast as well as porosity. If there are long intervals with high permeability intermixed, mechanical diverter would almost be considered as the sole solution especially when zonal isolation by the means of specialized tools is not required.

This work is aimed at the outcome from using a solid particulate diverter which is a biodegradable particulate diverter that maintains its diversion effect for as long as needed. By controlling certain factors, the diversion time can be increased or decreased. The diversion technique was first introduced to the Middle East in December 2016 to assist in finding a solution for the high permeable intervals that exist in Iraqi wells. The wells need to be matrix acidized and post stimulation PLTs show that production is coming from the high permeable intervals whilst other intervals that have lower permeability, showing no or low production because of the uneven treatment of the zone.

Lab tests were conducted to formulate a suitable carrier fluid that would possess optimum viscosity helping transport the solid particulate diverter system to the intended area. Along with, a suitable breaker fluid that would cleanly break the carrier fluid at the end of the treatment to assure efficient flow back is tested. Temperature and pH were maintained to simulate downhole conditions and achieve the most accurate results.

The job was successfully designed, prepared and performed. Real time optimization was conducted during the job which resulted in a more efficient operation.

The first observed post stimulation results was an increase of 5 m3 per hour. Two days following the stimulation, the records showed an increase in the production rate by approximately 25%.
Functions of Nanoparticles and Surfactants in Enhanced Oil Recovery: Molecular Dynamics Studies
Authors: Mazyar Oleg A. , Darugar Qusai A. , Khabashesku Valery N.
Published: November 2017

The roles of nanoparticles in enhanced oil recovery (EOR) are typically associated with stabilization of foams and emulsions (Fakoya et al. 2017) and with oil detachment due to creation of wedge effect in confined oil-water-rock contact region (Wasan et al. 2003). This publication focuses on these and other functions of nanoparticles in EOR applications, often performed in synergy with surfactant mixtures, e.g. abrasive removal of oil films from rock surfaces, wettability alteration, and improved transport of surfactant molecules through porous media.

Conventional and non-equilibrium Molecular Dynamics (MD) techniques were applied to simulate behavior of nanoparticles and surfactant molecules on oil-water-rock interfaces in stationary and flow conditions and compute the energies of interactions between the components of the studied systems as well as interfacial tensions in them.

Moving nanoparticles were found to be effective in detachment of oil film from rock surfaces. Increased temperature and addition of surface-active agent further enhance the oil-sweeping capability of colloidal nanosuspensions.

Changes in interfacial tension as well as density profile computations showed that functionalized silica nanoparticles and related surfactant-nanoparticle compositions clearly exhibit surface active properties on oil-water interfaces that can be fine-tuned and utilized in EOR applications.

The wettability-altering potential and surfactant-transporting capability of nanoparticles are also demonstrated.

Oil-sweeping, wettability-altering, and surfactant-transporting capabilities of nanoparticles are demonstrated on the molecular level for the first time. Authors also believe that it is the first systematic numerical study of nanoparticle's and surfactant's contribution to the changes in interfacial tension on oil-water interface.
Maximizing Cost Efficiency & Enhancing the Culture of Cost Consciousness Through Workforce Engagement
Authors: Khan Shahla , Saadi Israa Al
Published: November 2017

In February 2016 and in response to the difficult market conditions that had beset the oil and gas industry, Dolphin Energy launched The CORE Project – a long term cost optimization program.

Standing for Cultural Change, Optimizing Productivity, Resourcefulness and Efficient Expenditure (C.O.R.E), the Project was designed to generate significant cost savings and enhance a culture of cost consciousness. This paper outlines how the Project was implemented through the direct involvement of Dolphin Energy employees, who were tasked with providing ideas and suggestions that would help optimize costs and drive significant efficiency improvements to achieve long term, sustainable results.

Methods, Procedures & Process

To drive efforts across the company and ensure long term commitment, a collaborative ‘bottom up’ approach was created. Twenty nine Division/Department Champions were appointed in Qatar and the UAE while a governance structure was put in place, monitored by a Steering Committee and chaired by the General Manager - Qatar. The project is managed through three main phases:

To help drive engagement, the Project has been supported by a comprehensive communications program. This has been designed to provide regular updates on the program, to help maintain momentum, celebrate success and reward employees for their commitment.

Results, Observations, Conclusions

In the past 18 months, employees have generated more than one thousand ideas, of which more than 244 ideas have been converted into initiatives that have led to significant cost savings.

The project has also created tangible cultural change and has made employees more cost conscious and aware.

The CORE Project has received many enquiries from Dolphin Energy's peers in the Oil and Gas industry and the company has been proactive in sharing this experience with its shareholders, and its strategic partner.

Novel/Additive Information

This paper will help highlight the benefits of employee engagement and would be of interest to companies looking to use the workforce to drive tangible, sustainable results.

The CORE Project is a strong example of the effectiveness of a collaborative, ‘bottom-up’ approach, with ‘top down support’ and demonstrates that by involving everyone at the company amazing outcomes can be achieved.
Invisible Lost Time Reduction and Drilling Risk Management Optimization in United Arab Emirates Onshore Field
Authors: Cantarelli Elena , Kojadinovic Nenad , Le Khoa Pham , Salem Gamal Youssef
Published: November 2017

A new workflow was implemented for the first time in three UAE onshore wells with the primary objective being to increase drilling efficiency while managing the associated risks.

The workflow combines proven technologies, software and wellbore surveillance services to deliver risk-free wells ahead of authority for expenditure (AFE) targeting the reduction of nonproductive time (NPT) and invisible lost time (ILT), together with risk management.

The workflow begins with a preliminary field analysis to identify the main challenges and areas that needed improvement. The observations are consolidated on a comprehensive drilling road map by well section that are used to outline prevention and mitigation measures, expected rate of penetration (ROP) and recommended drilling parameters. The study also allowed for identifying performance benchmarks such as average and on bottom ROP and connection time. Key performance indicators (KPI) were developed to monitor progress and track the well with respect to well improvements versus the benchmarks identified. The selection of the monitoring tools and modules required during the execution phase was developed based on the risks and KPIs identified during the field study and were further tailored to target specific challenges such as stuck pipe prevention, hole cleaning, shock and vibration, and connection time.

The workflow enabled the flawless execution of three onshore wells ahead of AFE with zero NPT. The closed loop monitoring enabled real time interventions preventing risks such as stuck pipe, ensuring shoe-to-shoe drilling, and avoiding potentially lost-in-hole (LIH) costs. This monitoring process also enabled significant ILT reduction, saving approximately USD 500k for the three wells.

This case study demonstrates the use of a novel approach to increase well construction efficiency by eliminating lost time while enhancing risk control. The main basis for success of this workflow is using existing and cost-effective technology while capitalizing on the renewed synergy between different departments such as drilling, mud logging, and well operations analysis.

The workflow can be customized based on the different needs by combining specific modules for monitoring, analysis, and wellbore surveillance services to increase the efficiency of any well construction.