bluuebunny/crossref_metadata_2025_split huggingface dataset:
Industrial Power Augmentation Technologies for Aero-Derivatives GT Used as Natural Gas Compressor Drives
Authors: Martinez Guillermo 
Published: November 2016

Abstract
Gas Turbines are widely used for Mechanical Drive applications, especially compressor drive for LNG Plants. Aero-derivative turbines are increasingly used for this application as they offer many advantages in terms of superior efficiency and fast start up and reaction to changing demand. However, aero-derivative turbine are highly ambient dependent. When the weather gets hot, gas turbines lose up to 20-40 percent of power output and consequently the production of the LNG plant decreases. Efficiency also decreases when the ambient temperature is higher.
The high ambient dependency of aero-derivative turbines has been the main drawback of this technology in very hot climates. Turbine inlet air cooling (TIAC) has been proven to be the solution for this challenge, especially in Middle East. The technical background behind this phenomenon is that aero-derivative turbines have a fixed volumetric inlet air flow. When the ambient air temperature increases the density of the air decreases and therefore the inlet mass flow decreases accordingly. As the power output of the gas turbine is proportional to the inlet air mass flow, for higher temperatures the output will be lower. With TIAC technologies, the inlet air is cooled to avoid the problem of high temperature and low density.
TIAC has been implemented in the power sector as a cost efficient power augmentation solution for more than 25 years but it is not common for gas turbines used in Oil & Gas fields because of two main reasons: ▪For the las years, Oil & Gas market was not so much concerned about cost▪Standard chillers are not able to comply with the high requirements of the Oil & Gas Industry
However, the falls in oil price are forcing the industry to find solutions for capital cost reduction, which together with the state-of-the-art TIAC technologies characterized for using API standard industrial compressors, is recently turning TIAC a cost effective needed technology in the Oil & Gas sector. Initial examples include the last greenfield developments made by Saudi Aramco and Gazprom in which TIAC technologies has been considered and successfully implemented to reduce the overall capital cost.
After several years of successful operation and data collection, the results of the TIAC system implemented in three LM6000-PC located in the North of Mexico will be presented. The power output and heat rates were measured with and without cooling, and the CAPEX and OPEX was evaluated and compared with the installation of a new gas turbine. Based on those results, it is found that capital and operation cost is significantly reduced with TIAC for aero-derivative turbines at Oil & Gas fields.
NAD 360 Management Tool - An Innovative Approach for Reducing Risk of Non-Accidental Death at Labour Camps
Authors: Qureshi Farrukh , Karyum Hanafi , Al Blooshi Maha 
Published: November 2016

Abstract

Objectives/Scope
An innovative, universal, and first-of-its-kind management tool was developed that helps minimizing risk of Non-Accidental Death (NAD) at labour camps. NAD 3600 Management Tool supports prevention of NAD by ensuring proactive implementation of a comprehensive healthcare system at a defined level of effectiveness and periodic measuring and monitoring of capabilities and performance of a Contractor in provision of emergency healthcare facilities at worksite and camp. Tool can also be used for investigating a case of NAD.
An Innovative Technique for Relative Permeability Estimation of Tight Porous Fractured Limestone Formation- Laboratory and Numerical Simulation Studies
Authors: Aljehani Abdulrahman S. , Doonechaly Nima Gholizadeh , Rahman Sheik S. 
Published: November 2016

Abstract
This paper presents a new and innovative approach for the estimation of relative permeability of porous fractured carbonate rocks. The presented method differs from previous studies in that the relative permeability estimation for three different systems that exists in fractured rocks is measured. Fracture, matrix, as well as fracture-matrix porous systems are all taking into account with laboratory measurements of relative permeability and capillary pressure. In this study, both steady and un-steady states are used for the estimation of relative permeability in addition to the produced water during drainage flooding. Fracture surface topography is imaged by the use of surface scanning technique to determine the asperities of the surface and their heights. Simulation based on Reynolds equation is considered when developing the mathematical formulation of multiphase flow simulation. The developed mathematical model based on the integration of Darcy, cubic law and Reynolds to account for the variation of different porosity systems. The results simulated numerically are in a good agreement with the laboratory.
Geomechanical Solutions for Drilling Through Challenging Nahr Umr Shale at High Angle: A Case Study From Offshore Field, Abu Dhabi
Authors: Xi Guifen , Singh Rudra , Haddad Mohamed , Lecoq Thierry Francis , Al Badi Bader Saif , Zahaf Kamel , AL-Kindi Rashid Khudaim , AL-Wahedi Khalid Ahmed , Leblanc John , Singh Hemant , Perumalla Satya , Salter Tim , Imtiaz Saad , Kirby Cliff , Paila Phalgun 
Published: November 2016

Abstract
ADMA-OPCO has undertaken a prestigious campaign to drill a large number of wells from artificial island in ABC field, most of these wells are extended reach drilling (ERD) wells with step-out up to around 18,000 ft. Operational efficiency/costs for drilling ERD wells is highly dependent on the wellbore stability, especially while drilling through the problematic Nahr Umr shale at different deviations and azimuths. Nahr Umr shale has a known history of causing wellbore instability in UAE and the surrounding countries and therefore a geomechanical study was initiated to understand the geomechanical setting in ABC field as well as fluid-rock interaction between drilling fluid and Nahr Umr shale formation. The main objectives of this geomechanical study were to optimize well design and drilling fluids in order to drill through Nahr Umr shale interval efficiently, additionally estimation of sustainable pressure variation that major faults can take without being reactivated was also performed.
An integrated geomechanical study including a 3D geomechanical modeling was carried out, in order to ensure drilling through Nahr Umr shale formation efficiently. This study covered formation petrophysical characterization, chemical tests on cuttings from Nahr Umr shale, chemo-poroelastic modeling, weak bedding analysis and also faults reactivation analysis.
Based on the study mentioned above, both customized drilling fluids program and suitable mud weights were optimized to stabilize Nahr Umr shale, and mitigate different types of wellbore instability issues. In addition to mud fluid optimization, the sustainable pore pressure variation was also estimated for several major faults.
A successful drilling campaign is in progress; so far many deviated wells have been completed without any noticeable troubles while drilling through Nahr Umr shale. This geomechanical model is helping to implement an effective drilling program for a smooth well placement. A learning curve has been building up continuously for handling more complex well trajectories successfully in the future. From this study, it was realized that, not only fluid-rock interaction and geomechanics related factors need to be taken into consideration for stabilizing a wellbore, but also special attention is needed for the existing micro-fractures within the formation, where increase in mud weight may make hole condition worse. A balanced approach has been adopted including drilling fluid optimization in order to avoid possible multiple failure mechanisms.
Heat Stable Salts Accumulation in an Acid Gas Removal Unit
Authors: O'Neill Stephen 
Published: November 2016

Abstract

Objectives/Scope
During 2015 a marked increase in the concentration of heat stable salts (HSS) within amine circulating around this unit was observed. This paper will present how the root cause of HSS accumulation was identified and addressed and also provide feedback from amine analyses indicating the concentration of individual HSS components that were identified to have been the main contributors to accelerated corrosion of the unit in this instance.

Methods, Procedures, Processes
An Acid Gas Removal Unit (AGRU) was installed within the Dolphin Energy onshore gas plant to remove H2S and some CO2 from raw gas prior to further processing.

Results, Observations, Conclusions
A root cause analysis identified that a failure of the nitrogen blanketing system on the Lean Amine Storage Tank had been the origin of this HSS accumulation, and measures were taken to avoid any future re-occurrence. However, the resulting high HSS concentration in amine had already begun to cause accelerated corrosion of the unit, in particular within the AGRU Stripper Reboilers.

Novel/Additive Information
The paper will be of interest to all those involved in the design and operation of Acid Gas Removal Units and to those involved in the reclaiming of amine within such units. It will add to the body of literature already available from others that have experienced similar problems resulting from increased HSS concentrations in amine within AGRU's.
Optimizing Well Location in Clastic Reservoir Using Seismic Inversion for Onshore Field Located South-West Abu Dhabi
Authors: Ghafri Thuraya Al , Neves Fernando , Lakhlifi Assia 
Published: November 2016

Abstract
One of the target formations of the studied field is a clastic reservoir of the Middle Cretaceous. This particular formation is comprised of multiple sand units (bars, channels), with varying thickness and lateral discontinuity, separated by thin shale intervals. Due to data limitation and complex depositional environment, the delineation and reservoir characterization of this clastic sequence is relatively complex. This paper describes the workflow used to extract information about the acoustic properties (acoustic impedance) of the target formation and infer additional knowledge of the reservoir properties (porosity) using a model-based deterministic post-stack seismic inversion.
The area of interest (AOI) is covered by a recent high quality 3D seismic survey which has been processed through true-relative amplitude pre-stack time migration. Few wells containing monopole sonic, density and gamma-ray logs were available in the AOI. A basic feasibility study comprising rock physics, 1D well-log based seismic forward modeling, seismic-to-well tie and wavelet extraction was carried out prior to running model-based acoustic impedance inversion. The input seismic volume was post-stack pre-conditioned prior to inversion in order to enhance the usable frequency bandwidth and to reduce residual noise. Several techniques (with and without wells) were used to extract the seismic wavelet. A range of background (low-frequency) models were constructed using different methods and their impact on the inversion was appraised with the assistance of blind wells and classical inversion diagnostics.
The resulting average map and cross-sections of acoustic impedance (AI) enabled to locate the areas of high porosity (low AI) within the target formation. Consequently, in addition to seismic interpretation, we could optimize the location of the candidate well within the high porosity area. The generated AI helped in refining the seismic interpretation of this clastic reservoir as well.
Despite the complexity and the unpredictability of the Clastic reservoir depositional environment, Post-stack seismic inversion was a powerful tool that helped to locate the areas of good reservoir quality and ultimately to optimize the location of the candidate well.
Generating Cost Reduction in the Supply Chain by Coupling Surface Facilities with Reservoir Data in Integrated Asset Modelling
Authors: Harley John , Abel Clive , Watson Martin 
Published: November 2016

Abstract
Integrated Asset Modelling (IAM) processes can be used to quantify and monetise reservoir potential during the concept design process. Through quantification, risks can be mitigated and managed to deliver greater certainty through the concept selection process. IAM can be deployed throughout the hydrocarbons upstream sector to deliver robust field development and concept design solutions with more robust project economics.
IAM offers significant value and potential to identify supply chain cost reductions across the full spectrum of upstream developments, from full field development planning to individual equipment item modifications. The process offers particular value in development planning; in identifying and assessing sensitivity options and in definition of the optimum concept.
Full IAM incorporates expertise in reservoir, flow assurance, facilities and project economics expertise into a single integrated asset model. The process defined here is most effective as it is built upon integrating industry and in-house software, a combination of which facilitates Life of Field analysis to be carried out within a single package. The process offers unparalleled speed and flexibility in identification and analysis of concept design sensitivity cases. The IAM approach offers significant advantages and benefits to operators in addressing the three main reasons for destruction of project value; poor estimation of reserves, schedule overruns and cost overruns.
This IAM process is configured for fast and robust evaluation to ensure the right decisions are made at the right time based on the right information. The process will therefore preserve project value for operators and reduce the risk of value erosion through over or under engineering, or project recycle.
A Robust and Environment Friendly Artificial Lift System: ESPCP with PMM
Authors: Zhu Shijia , Hao Zhongxian , Zhang Lixin , Wang Quanbin 
Published: November 2016

Abstract
Up to 2015, the number of oil wells has reached more than 200,000 for CNPC. It is estimated that conventional beam pumping units are applied to 87% of wells. The traditional pumps suffer from eccentric wear between sucker rod and tubing and high electricity power cost, especially for deviated and horizontal wells. In this paper, we introduced a new artificial lift system, electric submersible progressive cavity pump (ESPCP), to solve these problems.
The new system includes a progressive cavity pump driven by a downhole permanent magnet synchronous motor (PMM), the motor protector and flexible shaft connecting the pump and the motor. In the design no gear reducers is used, which is the most likely failure point, in order to increase the robustness of the system. The motor protector is filled with oil for the lubrication and cooling of the motor. The speed of motor can be adjusted by frequency inverter on the ground from 50 to 500 rpm according to the liquid producing capacity. The operators can remotely control the working state of the system and the running data can be transmitted to the server in the remote office.
We have used the ESPCP systems on 4 troublesome wells for field trials in Jilin oil field. The results show that the system can save more than 20% of the electricity power and double the working life comparing to the traditional beam pumping unit system. Moreover, the system is located at the bottom of oil well, so less site occupation and less noise pollution to the environment are achieved.
The low electricity power and less frequent workover operations can reduce cost especially for the low oil price period. This paper will elaborate on the key learnings based on these field trials.
Successful Well Testing Operations by Using a Single Trip Retrievable Isolation and Testing Packer in Ghasha Appraisal Well Offshore Abu Dhabi
Authors: Jimenez Jose , Slatewala Huzefa , Negron David , Huda Shamshul 
Published: November 2016

Abstract
The discovery of offshore sour and corrosive gas reservoirs and the need to satisfactorily drill and produce them began in the late 1950's. The Ghasha 15 well includes deep oil / gas reservoirs containing up to 38% H2S and 7% of CO2. The objective was to perform safe and efficient drilling and several well testing operations in a highly corrosive environment with a rig that was located in a stand-alone offshore location in Abu Dhabi. The well was an exploration well in a location considered wild or remote well; there was no tower or platform facility with pipe lines to support the well testing operations available. 14 x well drilled previously were unsuccessful in obtaining the necessary reservoir data to prove deliverability. These challenges required the use of state of the art technology and highly reliable down hole equipment to subsequently enable successful exploration & appraisal of future UAE giant gas field development optimization.
Among other down hole tools and surface equipment used, highly sophisticated DST tools including HPHT high integrity packer, acoustic wireless telemetry systems, Dual Ported Slick Joints (DPSJ), flanged connections, surface close loop well testing package, special H2S and fire & gas detection systems and dispersion modelling were designed to successfully deliver the required data for field developments.
Attention to detail, rigorous planning, team work, multidiscipline input and approach were some of the key success factors in delivering the objectives in a safe and efficient manner.
While many drilling, data gathering, surface and down hole tool solutions were employed, this abstract will focus solely on the packer equipment and deliverability
Lesson Learnt from Immiscible Gas Injection Pilot in Offshore Carbonate Reservoir
Authors: Agrawal Pawan , Kumar Jitendra , Draoui Elyes 
Published: November 2016

Abstract
Hydrocarbon gas injection projects are undertaken in order to maintain reservoir pressure, produce oil through swelling and reduce residual oil saturation by decreasing the interfacial tension (IFT). Along with local displacement efficiency, macroscopic sweep efficiency plays a dominant role in the success of gas injection projects, as recovery from the field depends strongly on reservoir geology and petrophysical properties.
In this paper, a case study of one of the hydrocarbon gas injection pilots is discussed as the performance of the other two pilots has already been described in Kumar et al. 2015a. A five-spot pattern hydrocarbon gas injection pilot in tertiary mode has been carried out in a giant carbonate reservoir offshore Middle East, which has long peripheral water injection history. A comprehensive monitoring plan, including an observer well, was applied through time-lapse saturation logging, single well chemical tracer test (SWCTT), pressure measurements, production testing, and tracer campaign to assess the pilot performance and minimize uncertainties before large-scale application.
This paper presents the overview of the pilot, monitoring plan and the findings which include microscopic and macroscopic sweep efficiency. The pilot areal sweep performance was affected by the existing pressure gradient of peripheral water injection while the vertical sweep efficiency was strongly affected by the reservoir heterogeneity. At the cessation of the pilot, a value of 6 ± 3% was measured from SWCTT in the producer well, which shows the robustness of the gas local displacement efficiency. The history match performed indicates that for the same pilot, the performance can be improved using horizontal line drive in place of five-spot pattern and it can further be enhanced through water-alternating-gas (WAG) injection. The learning from the three gas injection pilots is used in re-designing the future large-scale development plan and is described in details in Kumar et al., 2016a and 2016b.
New Drill Bit Technology Sets Drilling Records in Carbonates and Harsh Rock Applications
Authors: Rahmani Reza , Bradford John , Barocio Hector 
Published: November 2016

Abstract
Harsh rock applications in general, specifically carbonates, are challenging in many aspects: 1) A combination of rock ductility and high strength contributes to low rate of penetration (ROP) in carbonates. 2) Applications are generally interbedded. 3) Significant thermal degradation of the cutters, especially in the shoulder area of the PDC bits, costs companies premature bit wear and unwanted extra runs. This paper presents the development of a new drill bit technology that addresses those challenges.
More than 40 pressurized laboratory experiments were conducted on Carthage limestone to identify proper positioning of a new shape cutter for carbonate applications. Furthermore, computational fluid dynamics (CFD) coupled with finite element analysis (FEA) were implemented to evaluate solutions to prolong the thermal life of the PDC cutters. This resulted in development of a novel nozzle geometry to cool and clean primary cutting structure as well a dedicated flow path for the secondary cutters. After successful laboratory testing, the new product and features were tested in several field applications in both North America and Middle East.
A Design for the Evaluation of a Waterflood EOR Technique by Single-Well Chemical Tracer Test in an Offshore Environment
Authors: Webb Kevin , Marrion Maynard , Stapley Jon , McCormack Martin , Williams Dale , Salino Pete , Al-Busafi Badar , McNeilly Kevin , Yammahi Fatmah 
Published: November 2016

Abstract
Single-well chemical tracer tests (SWCTT) have proven to be a valuable technique for evaluating Enhanced Oil Recovery (EOR) responses in clastic reservoirs. Development of carbonate waterflood EOR technologies are relatively immature in comparison, but the use of SWCTT for providing evidential basis in the field promises to be quick and relatively inexpensive compared with inter-well trials.
SWCTTs measure the remaining oil saturation (Sor) to waterflood at a 15-20 feet distance from the wellbore. The technique indirectly measures the Sor by analysing back-produced fluids for partitioning tracers in a well which is producing at 100% water cut. Completing the test pre- and post-EOR treatment quantifies the EOR benefit, at least in that near-well region.
Laboratory studies suggest that the use of ionically designed waters for EOR in carbonate reservoirs is temperature sensitive. This makes the design of a single-well test complex as it is essential to understand the thermal behavior of the well and the near-wellbore reservoir during any sequence of SWCTTs. Commercial simulators were used to investigate the thermal characteristics of the well and the near-wellbore reservoir respectively. These simulation results were also benchmarked against a water injection trial in another analogous well. The results showed that to ensure the temperature in the near-well region is kept sufficiently high to trigger an EOR response, it is necessary to pre-heat the injection water to &gt;100°C. This is a complex operation especially offshore where the technical and HSE considerations need to be integrated into a sufficiently-sized heating system where space may be limited. Artificial lifting of produced fluids from a well which is producing at 100% water is also problematic offshore. Benefits and drawbacks of various lift options will be reviewed. The effect that delays during the production phase can have on the quality of data from the SWCTT will be shown as well as the options considered to reduce the likelihood of such problems occurring.
The need to test this EOR technique in a controlled manner places stringent requirements on the surface facilities to deliver a test within the design specification. The need for low salinity water injection led to the selection of an integrated water treatment system able to produce desalinated water on-demand.
This paper is the first of a series of papers aimed at describing the development of an ionically designed waterflood EOR technology for a giant carbonate oil field.