bluuebunny/crossref_metadata_2025 huggingface dataset:
A Specific Approach to Petrophysical Evaluation in a Complex Carbonate Reservoir
Authors: Panda A. , Darous C. , Al-Kindi Z. , Amor F. Ben , Akram A.H. , Kriplani S.
Published: November 2016

The wells of this study have produced from two stacked Carbonate reservoirs which are characterized by variation in interparticle porosity along with a variable secondary porosity system of dissolution from vugs and fractures. The objective was to characterize these heterogeneous reservoirs in the absence of core data and to define consistent petrophysical models including porosity, permeability, rock quality indicators and saturation height models that considers the complexity of the reservoirs to be simulated.

Since no core data is available, the NMR T2 distribution and derived permeability (scaled to mobility from well tests) were correlated with borehole image features in key well to define the rock typing scheme. The saturation height functions were developed directly from the SW from resistivity logs by transforming and adjusting NMR T2 distribution to saturation height. In wells with only conventional logs, the SHF was used to back calculate permeability within the transition zone. In horizontal wells, a layering framework was built using electrical image logs for modeling high conductive features (vugs and fractures).

In the key well, the NMR T2 distribution reveals important variations in pore size distribution that enabled to establish a robust rock typing index based on Lucia Rock Fabric. The permeability estimated from NMR log was adjusted to match mobility from MDT. By transforming the pore size distribution from NMR to saturation height, a close correlation with the SW from resistivity logs is observed. The saturation height function allows within the transition zone to back calculate permeability from log derived SW in wells where NMR log is not available thus capturing heterogeneities in all wells.

For building a 3D property model which can include the layers contributing to dual porosity and permeability, a layer based model was defined in horizontal wells using borehole image dips and textural characteristics, petrophysical interpretation and production data as inputs. The correlation between wells indicate that the shallow most layer shows highest secondary porosity and conductive fractures. Despite the absence of core analysis, limited special logs and a mixture of vertical and horizontal wells with only conventional logs, the petrophysical properties of carbonate reservoirs with complex depositional and diagenetic features can still be established by associating the existing information into a coherent petrophysical model.

The novelty of this study is the construction of consistent permeability and saturation height model for a complex pore network carbonates formation using NMR logs in a key well that honors the log derived saturation profile and allow to back calculate permeability in wells with absence of core and limited log dataset. The construction of detailed layering along horizontal wells based on electrical borehole images is highly beneficial for developing the reservoirs models.
How Safe is the Existing Pipe Rack ? - Gasco Road Map
Authors: Shenoy Manur Ajith , Adel Khalid , Al Awadhi Ibrahim
Published: November 2016

Successive brownfield projects in GASCO plants utilized spare space on existing pipe racks to route new pipes. These pipe racks were originally designed as per erstwhile industry standards and environmental data, which have become obsolete over the years. In the absence of distinct guidelines, indiscriminate approaches were followed to confirm adequacy of these racks in order to reutilize them. Most of these approaches were irrational, had design flaws and raised serious concerns on the safety and integrity of the existing structure. This paper presents the full-fledged methods and procedures followed in GASCO for adequacy check and modifications of structures that assures high level of integrity of existing racks.

Adequacy checks present diverse challenges such as unavailability of as-built documents, want of primary analysis model, revision of codes etc. GASCO has developed an exclusive design guideline for structural adequacy check and execution of modifications, as a consequence of few incidents of failure of old pipe racks. Based on ‘Available' and ‘Not Available' state of required data, the pipe rack is grouped into different categories and stepwise design procedure is outlined for each of the categories. Tips on usage of right codes, estimation of missing loads, elimination of design errors, essential design checks, etc., are supplied. Practical techniques for strengthening of structurally deficient existing members and foundations are elucidated with sketches.

Development and implementation of common guideline encompassing all the design requirements for adequacy check and reinforcement of existing structures has resulted in unifying the approaches across GASCO plants thus ensuring a high level of safety and integrity of the existing pipe racks used in expansion projects.
Broadening the Horizon for Application of Process Safety Tools
Authors: Godfrey Michael John
Published: November 2016

Both Hazard and operability study (HAZOP) and Layer of Protection Analysis (LOPA) are two recognised techniques (or ‘tools') in the Process safety toolkit. Application of these techniques however has historically been restricted to a limited range of operations within upstream. This paper will describe how these tools can, and have been, successfully applied in broader applications.

HAZOP was first applied in the heavy organic chemicals division of Imperial Chemical Industries in 1963. The technique was subsequently developed and matured over the following years. Today in the upstream industry HAZOP is typically applied to both existing process operations and new projects. LOPA generally follows after a HAZOP to perform a semi-quantitative assessment of the event likelihood. Application of these techniques however has historically been restricted to a limited number of operations within upstream. The objectives of the paper are to i) describe examples where HAZOP has been successfully applied to novel operations and activities ii) show how LOPA can be applied, not just for determination of Safety Integrity Level (SIL) but to hazards not associated with an instrumented function and iii) demonstrate that broader application of these tools can lead to and improved understanding of risk and, through effective risk reduction, create value for operating companies.

An overview of potential challenges associated with implementing this adapted approach towards HAZOP is described, but also possible solutions. Following this the links between HAZOP and LOPA, including the information flows from one study to another are re-capped. This includes highlighting the difference between safeguards and layers of protection and qualitative risk assessment (HAZOP) versus semi-quantitative (LOPA). Current triggers for applying LOPA are compared to other approaches that result in a broader perspective and applicability. The key here is to demonstrate that there are a number of additional hazards that may be identified through HAZOP study, but for which an instrumented function may not be provided. As a result these are currently not always taken forward for further, semi-quantitative assessment. This current approach therefore limits our understanding of the associated risk.

In summary, through the use of example scenarios, the paper reveals some of the limitations resulting from restricted application of HAZOP and LOPA. The intent is to raise awareness of how companies are applying these tools to analyse additional operations or activities and, as a result, reduce the frequency of high severity events. The key conclusion is that these existing tools i) with some effort can be readily applied to new / novel areas and ii) can help management understanding of risk and provide assurance that these risks are being adequately managed. In short to fully understand the Process Safety risks associated with our projects and operations we must look to broaden the application of both HAZOP and LOPA tools.
Breakthrough Technology for Produced Water Desalination
Authors: Baldoni-Andrey Patrick , Jacob Matthieu , Pedenaud Pierre , De Souza Guillaume , Callaud Pierre , Dautriche Bastien
Published: November 2016

The petroleum industry produces much more produced water than oil and this trend is accelerating constantly. Desalination is an option to recycle water for smart water injection, to make EOR much more economically attractive by reducing chemical doses, or to reuse water for the benefit of surrounding communities in the frame of a shared-value program.

In order to find an alternative to reverse osmosis and evaporation processes, Total initiated a collaboration with Adionics, which has developed a new technology based upon liquid-liquid extraction. The solvent is not soluble in water and has a stronger affinity than water for specific or all salts. By reversible displacement of the salts from water to the solvent, desalination takes place in a set of extraction reactors or column. A second set of reactors or column operating at higher temperature enables regeneration and recycling of the solvent.

The process efficiency was initially validated in 2014 on solutions containing sodium chloride, and other salts. Then, Total and Adionics decided to evaluate this technique on several produced water samples from oil fields and gas fields. A full experimental matrix was developed and carried out in 2015 at Total R&D center to evaluate performances of this new process. The presence of the mineral and organic components, such as hydrocarbons, did not affect the process’ performances. The results clearly demonstrated that it has the potential to be applied to produced water at salinity much higher than sea water and up to 150 g/L of Total Dissolved Solids.

In 2016, Total and Adionics are preparing a pilot test (around 100 m3/d) with other industrial partners to validate those promising lab results at a pre-industrial scale. The objective for all industrial partners is to qualify a new alternative for water desalination which has a lower cost and a smaller footprint on environment (energy consumption) than conventional treatments such as evaporation/crystallization.
Design Optimization of Anti Surge Control Valves on Turbocompressors
Authors: Doenni Markus , Grutesen Lothar
Published: November 2016

This article describes the development process for a new control valve by means of Parametric Modelling Technology for the inner geometry of the valve housing. Typically a development process starts with a fixed 3-D CAD model. Subsequently the hydrodynamic properties of the design (such as the flow resistivity of a pipe element) are then calculated by CFD using standard boundary conditions. Very often and based on the calculation results the engineer has to adjust the model and then starts the loop again. In our case the design object is defined by a variable parametric geometry only. In a computerized iteration process using an upfront CAE tool, the system will automatically converge to an optimum solution. The results are amazing.
Modified Intervention-Less Inflow Control Device for Water Management
Authors: Sadana Anil K , Agrawal Devesh K , Noui-Mehidi Mohamed N
Published: November 2016

Excessive water production shortens the life of producing wells and severely limits their economic viability. Inflow control devices (ICDs) are used to halt water output and compensate for permeability variation by shutting off the sleeve where water production increases. Traditional ICDs need activation and intervention for the water shut-off, which leads to non-productive time, increased cost, and reduced revenue. Intervention-less passive technology addresses this imbalance issue by designing an ICD that highly reduces water breakthrough into the wellbore in virtually any porous media.

The intelligent well completion technology presented in this paper focuses on a modified ICD with no movable parts for water management. The ICD annulus is packed with a porous Polytetrafluoroetheylene (PTFE) sleeve that exhibits water-sensitive control functions. The porous PTFE sleeve causes a differential pressure for water and oil through the modified ICD. Differential pressure occurs because hydrophobic material and brine form droplets due to their higher surface tension, whereas oil flows in a more streamline manner. This situation leads to choking of the pore throat and higher pressure in the flow loop for higher brine cut. Flow testing through porous a PTFE sleeve shows about 200 % increase in differential pressures for 70% brine cuts compared to 0% water cut, which means it can restrict flow when the brine cut increases. The porous PTFE material has high thermal and chemical stability and can tolerate salinities as high as 246,000 ppm for long periods of time. Tests have confirmed the efficacy of the tool remains unchanged, even after flowing brine and diesel through the material for more than 400 hours. Prototype testing indicates that the modified ICD significantly improves recovery performance. This innovative tool will be field tested shortly.

This modified inflow control device offers a novel intervention-less, reversible subsurface water management technology by reducing production from zones with high water cuts.
Innovative Solution in Reducing Turnaround Duration
Authors: Al Jaberi Awadh Brek , Al Shamsi Abdulla Saeed
Published: November 2016

Turnaround is a major task involving large number of manpower, machinery and enormous activities. Success of Turnaround requires effective planning and efficient execution. Since ADGAS has three LNG Trains and two ASR Facilities, every year any one train undergoes a major turnaround. As LNG Trains 1 & 2 have several inter-connections, both Trains have to be shut down for the maintenance work scope in common facilities.

In the year 2015 LNG Train-1 Turnaround was planned for 35 days period including 8 days for common facilities maintenance. The work scope for common facilities was estimated to be difficult to be achieved in the provided 8 days window, due to space constraints and limitations arising from adjacent work in live gas manifold lines at ADMA.

A detailed study was conducted and a strategy was worked out in completing some of the common lines replacement prior turnaround without affecting production. It required critical changes in operating conditions, which were tested initially prior to carrying out the job.

By this more than 35% of the common facilities work scope was completed prior turnaround, thus achieving turnaround completion within the stipulated period.
Technology Enhancements in Effectively Modeling Sour Gas Processing
Authors: Sheikh Saifuddin
Published: November 2016

In gas processing and refining industries, natural gas and petroleum based feeds frequently contain sulfur in the form of H2S, SO2, COS, CS2, and other components. Even in small quantities, these acid gasses are hazardous to health and the environment, and removal is regulated prior to product sales. The removal of sulfur in midstream and downstream applications typically involves a series of absorption, extraction, oxidation, and conversion processes to form elemental sulfur, which is removed in liquid form and used in chemical applications, such as the formation of hydrogen sulfide or cleaning agents, and in commercial applications, such as fertilizer. A typical sulfur removal plant will typically contain an acid gas treating step, sulfur recovery (modified Clause) step, and tail gas treating step, before sending by-products to the incinerator/flare.
SIF Failure Probability Calculations – Comparison of Methodologies and Uncertainty Evaluation
Authors: Altamimi Maitha , Constantini Ahmed , Singh Vinod Pal
Published: November 2016

Risk is inherent in the facilities associated with petroleum and natural gas industry and various safeguards are employed to reduce the risk to the tolerable level. This paper is about instrumented safeguards which are referred to as safety instrumented functions. Specifically, the paper is the survey & comparison of the standards used for evaluating failure probabilities of safety instrumented functions. In designing as well as in maintaining the safety instrumented functions it is pertinent to know the differences in the methodologies of various standards and ensure that the overall approach yield pessimistic result to account for the uncertainties associated with the evaluation model and the associated failure data.

The paper starts with the qualitative discussion concentrating on the methodologies described in the various standards. To further aid in the analysis one example of a typical safety instrumented function, generally found in upstream oil/ gas facilities, is presented and is subjected to failure probability evaluation using different methodologies. The failure probabilities are then further analyzed for uncertainties with respect to the change in inputs.

The evaluation results are used to generate generic conclusions covering the two important aspects of the evaluation, i.e., models employed as suggested by the different standards, and failure data used in conjunction with the models. Along with the conclusions the challenges are also identified wherein further works are required in the ever evolving subject of safety instrumented functions.
Development of Crosswell Electromagnetic Monitoring System Using the HTS-SQUID Magnetometer
Authors: Harada Makoto , Yoshimatsu Keita , Kunishi Yosuke , Chiba Hiroshi , Hato Tsunehiro , Tsukamoto Akira , Tanabe Keiichi , Watanabe Hidehisa , Ishikawa Hidehiro
Published: November 2016

For accurate and stable monitoring of the oil/gas and fluid distributions in the reservoir during the EOR (Enhanced Oil Recovery) operation even if the well distance exceeds a thousand meter, JOGMEC (Japan Oil, Gas and Metals National Corporation) is developing a crosswell electromagnetic survey system with applying a super-sensitive magnetic sensor "SQUID" (Superconducting Quantum Interference Device). In this study, we have developed the component technologies of borehole SQUID magnetometer and powerful transmitter coil. The SQUID sensor performs in the temperature condition of 77 K, where the liquid nitrogen is available for cooling. To deploy the SQUID sensor in the deep borehole safely, we designed and trial fabricated pressure- and heat-resistant vessel which contains the glass Dewar of liquid nitrogen, release tubes of vaporized nitrogen gas, electrical circuits, and other devices to control the SQUID sensors. The developed transmitter coil has magnetic moment of 27,500 Am2, which will satisfy the intensity for our purpose. We demonstrated the stable operations of the prototype models of borehole SQUID magnetometer and transmitter systems with using the research wells of the JOGMEC field, of which maximum depth is 300 m and cased with conductive tube. The SQUID magnetometer has the ability to be deployed in the environment of 3,000 ~ 4,000 m deep boreholes by the laboratory experiments. At the next stage, we will demonstrate the systems at the actual borehole, whose typical depth is greater than 1,000 m. On the other hand, we have been developing the algorithms to interpret and correct the effects of conductive casing tubes, and three-dimensional modeling of underground structure. For the demonstration of their performance, we will also conduct the crosswell measurement with using the test wells.
Facing the Big Crew Change: Fast Tracking the Technical Development of Emirati Nationals
Authors: Al Daghar Khadija Ahmed , Ramamoorthy Raghu , Gunter Gary W. , Al Ameri Shamma Qarran , Habib Amir
Published: November 2016

National and International Oil and Gas Companies are continually seeking and applying new technologies, processes, and methods to reduce their cost of finding and producing hydrocarbons in order to maximize Return-On-Investment (ROI), and remain competitive in the current and challenging global economy. Improving the efficiency of business processes and maximizing the productivity of the workforce is a key component for success. A key strategic component is to reduce the time it takes to develop technical staff abilities, skills and confidence to become independent contributors.

Although technology has helped companies utilize advanced measurements it remains a challenge to develop Operations and Reservoir Petrophysicists. Strategic non-conventional training that is based on technical competency management skills assessment has emerged as a fundamental tool. Frequently, traditional training that is not competency based may lack the proper vehicles for training, technology and transferring knowledge to developing subsurface professionals. In some circumstances the lack of knowledge transfer may be jeopardizing oil and gas field development efforts.

The technical complexities of Operations and Reservoir Petrophysics can only be effectively addressed through the selection, and application of appropriate technology using a multi-disciplinary approach, hands-on, custom designed attachment program and well trained competent personnel. The skill development process must be managed using competency based assessments.

Each individual develops new skills at different rates and learns differently. For strategic attachment programs to be successful in transferring skills and knowledge it is essential to systematically identify the technology gaps and design project-specific knowledge training.

An efficient and effective way to do this is to establish core competencies for different job profiles, develop skills matrices and competencies assessments, and design training or competency improvement events to address these needs. We present a recent case study where ten Emirati nationals – 3 gentlemen and 7 ladies – of a major oil operator underwent and successfully completed a one-year attachment program in Petrophysics.
Compositional Simulation for Time-Lapse Seismic Modelling on a Synthetic Reservoir With a High Content of CO2
Authors: Pinto P. , Azevedo L. , Ribeiro M. , Gomes J.
Published: November 2016

This work focuses on the creation of a refined workflow for 4D seismic modelling using compositional fluid flow simulation on the synthetic reservoir CERENA-I, which mimics some characteristics of a real Brazilian Pre-Salt field. This reservoir has a saturated oil leg with a retrograde condensation gas cap, both with a high content of CO2, for which a production strategy capable of dealing with large quantities of gas was required and developed.

A rock physics model was built for this reservoir in order to compute time-lapse seismic reflection data with data retrieved from the compositional fluid flow simulation. This allowed assessing the influence of pore fluid changes in the seismic response of the reservoir and the creation of a dataset of time-lapse seismic volumes correlated with a production strategy, which can later be used in multiple seismic inversion studies.
Fully Implicit Coupling of Multiple Reservoir Models with Common Water Injection Facilities
Authors: Patacchini Leonardo , Bedewi Mahmoud , Farouk Magdy
Published: November 2016

The building, calibration and validation of a coupled simulation model treating two giant subfields simultaneously with their common water injection facilities are presented. The primary objectives of the project were to develop a tool providing more accurate forecasts by consistently allocating injected volumes to both subfields, and to help identify network upgrades necessary to accommodate the long-term development plan. Simulation results presented in this paper are nevertheless based on an eight-years (2015-2023) drilling schedule, followed by no further activity.

Building of the model involved migration of separate reservoir and network models to a next generation simulator capable of treating both surface and subsurface flows fully implicitly. Coupled model operation without network (i.e., with wells constrained by guide-rates considering a common field injection target) and with network (i.e., with wells constrained by self-consistently calculated backpressures) are discussed and compared in detail. For the latter case, particular care is necessary in terms of modeling injection modules.

Calibration consisted of shifting the lift performance curves of more than 200 active injection strings, in order to make up for any mismatch in the flowing wellhead pressure and help ensure rate continuity at the transition from history to forecast. Tuning of the surface network, modeled "as is" according to its physical layout, was not necessary based on the good backpressure match obtained for the more than 40 active injection towers.

Validation was performed through a one-year blind test, from April 2015 (start of forecasts) to March 2016. The procedure first involved well-by-well comparison of injection rates, for which, because of allocation uncertainties, a qualitative match was accepted; it second involved a comparison of the injection split between the two subfields, for which less than a 1% mismatch was achieved.
Pore-Scale Experimental and Numerical Study on Permeability Characterization of Abu Dhabi Offshore Carbonate Micromodel
Authors: Li Hongxia , AlFarisi Omar , Voort Bob , Dimas Clara , Zhang TieJun
Published: November 2016

Carbonate rock exhibits great diversity in composition, pore size, and surface wettability, all of which significantly affect oil recovery process. In this work, we studied the pore size distribution, porosity, and permeability of the rock sample from one of the Abu Dhabi offshore reservoirs.

To characterize the rock sample, mercury intrusion porosimetry combined with microscopic techniques were used. A digital pore-throat network was reconstructed by processing x-ray images of the rock sample. In order to experimentally visualize liquid/solid interaction and flow patterns, a polydimethylsiloxane (PDMS) microfluidic device was fabricated with the same digital pore-throat network map. Both flooding experiment and numerical simulation were performed to quantify the permeability and multiphase flow behavior inside the rock.

From the oil-water displacement experiment, irreducible oil trapped in dead-end pores and narrow throats can be clearly observed. Furthermore, the numerical Lattice Boltzaman (LB) simulation results show the influence of surface wettability on the oil trapping and saturation change. The absolute and relative permeability of oil-water system were calculated from the direct water flooding simulation results. Furthermore, a three multiphase flow was simulated and oil saturation was monitored in order to understand the mechanism of water-alternating-gas enhanced oil recovery. This paper provides a feasible solution, which takes advantage of the recently developed micromodel fabrication and simulation techniques, on systematic permeability characterization of heterogeneous carbonate rocks.
Assessment of Miscible EOR in a Giant Offshore Carbonate Reservoir
Authors: Willingham Thomas W. , Kohata Akihiro , Irwin Drew , Buang Kamarul , Al Sowaidi Alunood
Published: November 2016

In this paper we present a comprehensive assessment of the EOR potential in a giant off shore carbonate reservoir including a novel screening methodology to assess reservoir, fluid and miscible characteristics across various reservoir and geologic units. We employed a multi-disciplinary approach to identify potential pilot locations within the leading geologic and reservoir units and assessed the miscible EOR uplift through both an analytical assessment of potential to screen for the broad uplift within the targeted geologic areas and developed compositional simulation models for the pilot areas utilizing a history matched simulation model to estimate the uplift for the specific pilots. In this paper we utilize a quantitative estimate of incremental EOR potential utilizing an analytical estimate of sweep efficiency which is based on the viscous to gravity ratio (VGR) coupled with SCAL measurements of the remaining oil saturations to estimate the uplift from miscible EOR based on core flood results using hydrocarbon separator gas, CO2 and enriched hydrocarbon separator gas.

To identify pilot areas within the leading geologic areas, a multi-disciplinary Task Force spanning Field Development, Projects, Drilling, Well Operations and Facilities was formed. Key assessment criteria include pilots are geologically representative of the broader geologic area, pilots are aligned with field development plans, pilots are sourced from drilling and production centers (in this case artificial islands) with appropriate facilities (including corrosion resistant alloys if required), pilots are optimally located considering drillability and anti-collision, and pilot areas are of higher maturity such that field implementation can be expedited.

Identified pilot areas were then assessed for miscible EOR uplift utilizing a history matched compositional simulations with a tuned Equation of State (EOS). Sector models for the pilot areas were created to investigate the uplift in incremental recovery under various WAG ratios, gas injection schemes, injection gas timing and PV injected. In summary, a unified methodology was created to access miscible EOR potential, rank various reservoir and geologic areas, specific pilot areas were identified, and miscible EOR potential was quantified for the identified pilot areas using compositional simulations based on a tuned EOS and history matched simulation model.
CO2 Detection Using Graphene Based Micro Sensors
Authors: Al Shehhi A. , Al Suwaidi M. , Al Hammadi I. , Saadat I.
Published: November 2016

Oil and gas industry encounters challenges whenever EOR/EGR is being introduced; numerous methodologies have been looked upon at an early stage of analyzing the recovery solution. Generally, there are numerous types of pipelines used in the oil industry; and each has its associated operational issues. There are certain mitigation plans for the oil production pipelines that have to be adopted, especially after implementing the CO2 injection as an EOR methodology into selected depleted reservoirs.

CO2 injection is used to enhance oil recovery (EOR); henceforth it is consequently commingled with other gases like the H2S. Such commingled gases are considered corrosive and may lead to cracks and fractures to the pipelines. The thermodynamic property of CO2, influenced by the temperature and pressure during pipeline transportation, with the existence of other gases (such as H2S), makes the presence of CO2 to be a coorosion driver in the pipeline. Therefore, such pipeline operation is considered to be more complicated than any other service pipelines.

This paper will represent the joint research conducted in Masdar Institute and ADCO, which deals with the fabrication of graphene micro sensors. These micro sensors are based on graphene as active material for the transistor like sensor systems. Graphene has unique sensing/electronic properties along with physical and chemical stability in corrosive and hostile environments required for the oil and gas application. The graphene films are synthesized and optimized using Chemical Vapor Deposition (CVD) reactor in various substrates with different surface finishes. Three different types of architectures of micro sensors are fabricated and will be reported, which are Kelvin, Backgated and Memberane. The response of each of these architectures helps triangulate and identify the presence (and concentration) of each of the targeted gases. For example, the membrane device will detect the presence of any physical precipitation in the oil/gas mix. While the backgated device allows for detection of ionic and polar species. This will help to give a high-level assessment and early warning for the pipeline integrity.

Our current delegated results include the fabrication of the three sensor types in Masdar’s clean room. This included the development of the various processing steps, design and fabrication of test devices and structures. This was followed up with development and characterization of the performance in various environments (gaseous and liquefied). These results have demonstrated the capability of graphene, as an active sensor material, to sense and determine the concentration of gases within different pressures, down to the 100’s of ppm level. Additional characterization assessments in different gaseous mixtures are ongoing and the results will be reported in the final paper.
Enhancing Smart Completion Capabilities by Integration With Digital Oil Field Real Time Monitoring System in a Green Field of ADMA-OPCO
Authors: Hussain Asim , Vega Juan Carlos , Hassane Mohamed Abdel , Yusaf Shabeer Ali , Abdul-Halim Abdulla Adam
Published: November 2016

This paper demonstrates enhancement of smart completion capabilities by integrating with digital oil field platform for effective performance management of dual lateral wells. Single smart completion with ICVs for controlled comingled production among two reservoirs was successfully deployed and commissioned for 03 oil producers in one of Abu Dhabi green fields.

The multi-position ICVs with customized flow trim design enabled regulating flow from reservoirs downhole and performance monitoring in real time. Additionally with launch of digital oil filed (DOF) in ADMA-OPCO, it is recognized as beneficial using the real time data monitoring to remotely control and operate smart wells for better reservoir management; helping to enhance the smart well system operating reliability. Production performance for one of the EPS smart well is also presented in this paper as a successful case history where the water production for the well was managed below 5% to keep the well flowing and resulted in saving the operating expense (OPEX) by US$ 478 K.

Three approaches were evaluated for flow allocation modeling among the two reservoirs and are presented in this paper i.e. a steady-state nodal analysis network model built in-house, virtual flow estimator (VFE) to provide real time results based on general choke equation and NETFlow (an alternate to VFE) based on a steady state simulator NETool capable of modeling complex lower completions; with later two approaches provided by the vendor and being optimized jointly with ADMA-OPCO. The steady state models are calibrated against the available PLT and real time downhole and surface flow- test measurements.

In the end, some unique issues observed with smart well completions, especially the functionality of the ICVs, are highlighted including the observed anomaly description and associated solutions implemented to restore functionality of some of the smart completion components.

Deployment of smart completions in this green field has resulted in simplifying the completion design and optimizes the number of wells required for field development. Integration of DOF with smart completion system has enabled the team to effectively manage the performance of the reservoirs (especially water production); in the absence of gas lift and continuous down-hole chemical injection during EPS tenure.
Operational and Asset Integrity Implications on Sour Gas Processing Facilities of Higher than Design H2S Carryover in Sweet Gas Leaving the Acid Gas Removal Unit Amine Absorber
Authors: Whateley Thomas
Published: November 2016

This paper presents the findings of a study into the consequences of H2S slip into sweet gas from an Acid Gas Removal (AGR) unit amine absorder. Whilst the study was initiated to investigate consequences to downstream consumers with respect to sales gas product specification, during this assessment the implications from a plant operational and metallurgical perspective were also investigated and found to be of critical significance and defined the maximum permissible H2S concentration in the sweet gas leaving the amine absorber.

The study assessed the maximum H2S concentration permissible in the sweet gas leaving the AGR amine absorber when considering stress corrosion cracking regions for the downstream plant materials of construction to determine maximum allowable H2S content in sales gas from a metallurgical perspective. The paper also investigated a multitude of operational implications regarding higher than design H2S in the plant sweet gas, including high H2S in the plant fuel gas network.

The study found that while the normal operating concentration of 3ppm(mol) H2S in the sweet gas is normally respected, the maximum allowable H2S concentration limit must not exceed 15ppm(mol) due to the risk of stress corrosion cracking in the downstream processing facility. This maximum limit from a metallurgical perspective also avoids all of the operational concerns identified.

In the event of an AGR amine absorber operational upset (e.g. loss of lean amine feed), after a relatively short duration, the concentration of H2S in the sweet gas leaving the AGR amine absorber rises rapidly beyond the normal operational concentration and will significantly exceed the 15ppm(mol) minimum limit. As such, plant modifications have been implemented to trip the AGR unit whenever process operating conditions exceed the normal operating envelope due to the potential of the sweet gas to go off spec.

This paper will be of interest to sour gas plant operators who remove H2S from their raw gas to meet a gas product specification using amine absorption processes. This paper presents findings of as study in to the operational and metallurgical consequences of exceeding H2S specification in Sweet Gas for a sour gas processing facility.
Successful Implementation of Flare Gas Recovery Systems in Gasco Plants
Authors: Allamaraju JagannathRao P , Mukherjee Rahul
Published: November 2016

Environmental issues such as global warming and economic considerations have resulted in the use of flare gas recovery systems to reduce flaring by capturing and either compressing the flare gases for other uses or recycling the flare gases to low-pressure process equipment.

Gasco requirement is to recover the flare gases of the three hydrocarbon flares instead of being continuously burnt. This should be through the installation of Flare Gas Recovery Systems (FGRS). This recovered gas should be either used as a fuel gas or injected back into the processing facilities.

World Bank has introduced the initiative "Zero Routine Flaring by 2030". In line with the above initiative, within Gasco there are KPIs which aim at reducing flaring and to recover the flared gases.

This is achieved through the successful implementation of Flare Gas Recovery Systems (FGRS) at GASCO Plants A, B and C.

Targeting Process Safety (PS), enhancement in HSE and performance monitoring, starting 2008, Gasco embarked on an ambitious Project requiring state of the art Flare gas recovery systems.

This Paper details the stages involved and detailed plan, i.e. Study, FEED and EPC. Optimization methodology necessary when designing or operating a reliable Flare Gas recovery Systems on existing Gas Plants to recover hydrocarbon gases over wide range of gas compositions without affecting the existing facilities.

A study was conducted on Hydrocarbon Flares of Gasco Plants A, B and C in order to predict the various continuous flow rates through the three Hydrocarbon Flare headers. It was predicted that for each of above plants the recovered gas could be in the order of ~1 to 2 MMscfd.

In FEED, considering the future additional flare gases, the design capacity of the individual flare gas recovery systems fixed at 5 MMscfd per train for each of above plants. EPC Package was developed to execute project on turnkey basis.

Proper FEED, EPC Detailed Design Review, HAZOP and SIL sessions produced an inherently safe Design.

In 2013 the project was successfully commissioned. The FGR system was found capable of operating at flowrates up to the design flowrate across the full range of molecular weights.

Actual recovery of Flare Gas post implementation on a yearly average basis for a period of three years (2013/2014/2015) are reproduced below:Plant A - 1.40 / 1.75 / 2.17 MMscfdPlant B - 1.58 / 1.78 / 1.86 MMscfdPlant C - 1.36 / 1.65 / 1.81 MMscfd
Improving Driving Safety at Rumaila Operating Organisation
Authors: Jacobs Louis , Clark Tony , Cornish Robert , Hughes Martyn , Jack William
Published: November 2016

The Rumaila Oilfield is the second largest oilfield in the world and is operated by the Rumaila Operating Organisation (ROO) a joint venture between South Oil Company (SOC), BP, PetroChina and the State Oil Marketing Organisation (SOMO). ROO has in the region of 6,800 personnel located at various locations throughout the Rumaila Field. With over 5,000 vehicles travelling across this area, occupying a foot print of around 1,300 sq. kilometres, driving is one of the most significant safety risks faced at ROO.

The road network in Rumaila covers 220 kilometres of roadways, comprising of asphalt, graded and ungraded roads. The Rumaila Field is split by an asphalt road, commonly referred to as the Spine Road, approximately 80 kilometres in length which is fed by five asphalt link roads from the surrounding towns of Al Zubair, Al Qurna and the city of Al Basra.

Whilst the Rumaila Field is operated by ROO, the Spine Road is traversed by local residents whose dwellings are encompassed by the geographical foot print of the contract and also by various service companies working on adjacent oilfields of West Qurna, Majnoon and Zubair. Those are in addition to the 300 companies operating on the Contract Area who are providing services to ROO.
Novel Approach in the Design of Friction Piles Resting on the Rock – Reverse Engineering
Authors: Yadla Nanda Kishore , Agrawal R. K , Oussama H. Takieddine
Published: November 2016

Offshore structures are supported by pile foundations to transfer vertical and lateral loads to the sub-soil. Based on the type of sub-soil, pile foundations are designed as driven or drilled & grouted piles. Design of the offshore pile foundation generally follows the guidelines of API RP 2A and API RP 2GEO. However, these guidelines being general it's applicability for complex soil-rock stratifications need to carefully reviewed. For the soils with sand/clay layers in upper stratum and rock or hard carbonate rock layers below these soft stratums, combined pile foundations are generally followed. These include driven pile in top soil with drilled & grouted insert pile in the rock below. However, this combined pile foundation has great impact on offshore installation time which directly influences cost of the project. From the design point of view, drilling through soil plug of driven pile has major impact on pile frictional and end bearing capacity. New design approach was developed for one of the platforms in the Arabian Gulf, where top soil is sand and clay up to 40 m followed by 10 m of Gypsum and 10 m of sand layers. Based on soil strata, composite pile option was recommended in the soil report with driven piles up to 40 m below mudline and insert piles of lesser diameter up to 55 m. However, this recommendation had an impact on project cost and also there was uncertainty in achieving required design pile capacity. For safe and economical design, a novel design was proposed by making use of rock end bearing to achieve the required capacity. However, in the geotechnical report rock design parameters for axial capacity were not reported and design guidelines are silent on capacity computation of driven piles in the rock. Therefore, end bearing capacity in the rock was back-calculated from the pile driveability analysis using the GRLWEAP software. With this back calculations and required design changes, composite pile option was eliminated and pile was designed with minimum penetration into the rock. This paper includes discussion on methodology, results, pre-cautionary measures, other additional requirements and cost comparison with conventional method. This new approach of pile design in complex soil-rock system is cost-effective and safe. This can be implemented for future platforms with the similar type of soil strata.
Advanced Well Modeling and Diagnostics to Manage Annulus Pressure
Authors: Srivastava Manish , Spuskanyuk Oleksandr , Abdulhai Walid , Alshehhi Ali S.
Published: November 2016

In order to monitor and diagnose B annulus pressure in the recently drilled extended reach drilling (ERD) and maximum reservoir contact (MRC) 30,000-35,000 feet-long wells a systematic study was conducted to understand causes of this pressure and to develop pressure management guidelines that will allow safe operation of these wells.

Newly-drilled wells were monitored from the construction phase to the well completion, handover, clean-up and then production phase with the focus on the following: Monitoring well parameters on daily basisBleed-off analyses (volumes and sample analysis)Review of the cementing job and the logs for 9-5/8" casing and 13-3/8" casingDiagnostic analyses including modeling and logs if necessaryMaximum allowable wellhead operating pressure (MAWOP) calculations

Detailed descriptions have been provided on how the annular fluid expansion volume due to a thermal effect was estimated using a computer modeling calibrated and history-matched to the field data. Results of modeling along with diagnostics using tools like spectral noise log (SNL), high precision temperature log combined with distributed temperature sensing have provided conclusive evidence that the wells are integral and safe to operate.

This unique combination of modeling and diagnostic tools allowed to optimize logging duration, minimize well shut-in time and improve fidelity of diagnostics through more detailed logging in the areas of interest. It was concluded that the main factors contributing to the B annulus pressure are the thermal effect seen during the well start up, the quality of cement job for the production casing, the volume of fluid in the annulus and the connectivity to the formation, if any. The study demonstrated that the wells are safe to operate with pressures below MAWOP and that B annulus is not in communication with the reservoir.