bluuebunny/crossref_metadata_2025_split huggingface dataset:
Understanding Overpressure Trends Helps Optimize Well Planning and Field Development in a Tectonically Active Area in Kuwait
Authors: Khan K. , Al-Awadi M. , Dashti Q. , Kabir M. R. , Aziz R. M. 
Published: June 2014

Abstract
Sporadic but significant drilling downtime, potentially linked to field-scale pore pressure anomalies, has occurred during drilling to a deep carbonate reservoir in North Kuwait. Some wells experienced well-control situations while some others suffered severe mud losses. The field data show that pore pressure can vary between 9 ppg and 19 ppg before a well reaches its target depth of approximately 15,000 ft (TVD). These observations require the establishment of a good understanding of the subsurface pore pressure in order to optimize drilling operations, assess reservoir risks and provide input for better well completions.
Geomechanical studies, utilizing pore pressure and temperature data from downhole measurements, openhole logs, drilling records and lithological information, were conducted to explain the overpressure mechanisms. Analyses indicate that overpressure above the reservoir appears to result mainly from hydrocarbon accumulations and subsequent gas generation during hydrocarbon maturation where pore pressure has been measured to be as high as 15 ppg. However, due to variable sealing conditions and field-scale faulting and fracturing, the pore pressure can vary within the same field. Pore pressure close to overburden stress (~20 ppg) observed while drilling through underlying salt and interbedded anhydrite layers is caused by trapping of water released during gypsum-anhydrite phase transformation. In the reservoir below salt, pore pressure varying between 16 ppg and 17 ppg can be attributed mainly to hydrocarbon generation and buoyancy effects. Towards the bottom of the reservoir, pore pressure is slightly low and varies between 14 ppg and 15 ppg. The severity of vertically and spatially varying borehole breakouts suggests that variations in tectonic stresses are present on the field scale, which may impact the generation of stress-related overpressure. Moreover, the intermittent presence of anhydrite layers and stiff intact limestone beds may act as localized seals generating overpressure.
Geomechanical analyses were subsequently used to constrain the contemporary stress state and fracture gradient profile. These helped explain hole stability issues experienced during drilling and assisted in planning future drilling operations. In addition, the data provided better quantitative input for reservoir risk analysis and well planning for the field development campaign.
A Simulation Framework for Multi-Scenario Production Forecasts in the North Kuwait Jurassic Complex
Authors: Ghorayeb Kassem , Aziz Rafi Mohammad , Penney Rick , Dashti Qasem 
Published: June 2014

Abstract
The North Kuwait Jurassic Complex (NKJC) consists of six fields with four potential reservoirs in the Jurassic age naturally fractured carbonate formation. Current understanding of the complex, has led to 12 subdivisions of the area and potentially 48 separate compartments (segments) in the complex. These subdivisions are defined by fault boundaries supported by a combination of variations in fluid composition, initial pressures and free water levels estimated from capillary pressure and log saturation data.
Multi-scenario production forecasts based on integrated full field modeling were needed in the process of building a Field Development Plan (FDP) for the NKJC. An integrated Asset Modeling (IAM) framework is adopted where multiple separate reservoir models (up to 48 models) are coupled through global constraints in order to meet gas delivery targets. The solution uses a black oil delumping technique to obtain compositional wellstreams while running black oil simulation models. The adopted simulation framework provides us with all the benefits of a compositional full field simulation model while topping-up with two advantages i.e. computational speed and flexibility.
We discuss the impact of the IAM solution on the selection of the optimal development scenario given that these fields are in the early stages of production via an early production facility on line in 2008. Coupling of all fields/segments allows optimization over the entire production system rather than optimizing each field individually. This reduces the number of wells required to meet targets at any one time under any reservoir realization, while also staying within the surface network constraints.
From Operations to Desktop Analysis to Field Implementation: Well and ESP Optimization for Production Enhancement in the Cliff Head Field
Authors: Dholkawala Zulfiqar Firoze , Daniel Simon , Billingsley Bill 
Published: June 2014

AbstractUnderstanding the integrated performance of complex artificially lifted wells on ‘not normally manned’ (NNM), offshore platforms, without invasive techniques represents a challenge not only to minimizing operating costs, but also optimizing production and thereby maximizing value. Often the analysis of such problems is hindered by the complex interactions between identified production constraints and a lack of operating data.The Cliff Head oilfield (offshore Western Australia) is developed with an innovative Coiled Tubing deployed Electrical Submersible Pump (CT-ESP) artificial lift system. This paper describes the process by which ESP and well data, in conjunction with a well performance modeling software, have been used as a powerful tool to diagnose well performance issues and optimize production. Production trends were created based on real time production data to understand ESP performance. Individual well models were created to identify potential causes of declining performance; in this case, the utilization of an ESP "performance limiting factor (PLF)" indicating deteriorating ESP performance due to solids build-up.Based on the model results, chemical soaks were implemented on two production wells to remove flow restrictions within and around the ESPs. The treatments increased the oil production rates by 17% to 48%Following a de-bottlenecking study, reservoir simulation in combination with detailed ESP performance analysis concluded that total field production improvements of up to 50% were possible. Consequently, the next phase of field development will install larger capacity ESP's.This paper outlines how field data and desktop tools were combined successfully to monitor and diagnose well performance issues to deliver material production enhancements.
Well-Performance Monitoring (WPM): Creating Added Value From Raw Data and Application to the Girassol Deepwater-Field Case
Authors: Khan F.. , Goujard V.. , Tincelin P.-H.. -H. , Tison M.. , Foucault H.. , Kessler N.. 
Published: June 2014

Summary
Capitalizing on early successes in advanced well control and realtime monitoring, Total Exploration and Production has engaged in a major "digital-field" initiative. Combining both proven and leading-edge technologies, the field-monitoring template is providing a powerful tool for well and facilities performance monitoring and optimization. This paper presents the concept of the WPM module, and the early results of its pilot application whose implementation began in 2009 at the Girassol field located offshore Angola.
The WPM module constitutes an integrated real-time monitoring solution for subsea installations, from reservoir inflow to receiving facilities. Proposing advanced features (e.g., a common asset model, a business orchestrator, and a Web-based interface), the tool provides remote access to timely and quality field data, improves communication and collaboration between offshore and onshore, and provides support by specialists from exploration- and-production headquarters. Functional capabilities include data validation, virtual metering, wells and networks modeling, smart alarming, and production optimization. Specific workflows have also been defined to sustain continuous updating of the models to match observed field behavior.
This paper illustrates the benefits of the WPM solution in terms of improved production and enhanced well diagnosis. It also reviews the organizational challenges associated with such a project and discusses the key factors ensuring successful implementation and good support from on-site teams.
WPM brings forth a new approach for the intelligent surveillance of complex subsea-production systems. Well performance and production and reservoir teams have gained benefit from such a tool. Pertinent information is delivered to the right people in real time, enabling instant diagnosis and minimization of production shortfalls. In addition, the online simulator supports the continuous optimization of the field throughput by real-time integration of changing well behavior or production constraints.
Alkaline Surfactant Flooding for Tight Carbonate Reservoirs
Authors: Mohan Kshitij 
Published: June 2014

Abstract
A laboratory study was undertaken to study the feasibility of oil recovery by surfactant flooding from an oil-wet carbonate reservoir. The unique features of the subject reservoir are its high salinity (and high divalent ion concentration) and low permeability (2–5 md). Alkali-surfactant combinations can be formulated which give low IFT (10−3 dynes/cm) at high salinity and hardness. Oil left after water flood can be mobilized by tertiary injection of low IFT surfactant formulations. Almost 95 % of the original oil was recovered in tertiary core floods using alkali-surfactant formulations. We could not identify a mobility control agent (polymer or foam) for such a low permeability rock. Thus slug surfactant processes were not attempted. A surfactant was identified which changed the wettability of oil-wet rocks to intermediate to slightly water-wet. 80% OOIP was recovered using the wettability altering surfactant in a secondary surfactant flood at 3 PVI in comparison to 60% from a waterflood at similar pressure drops.
Demonstration of Low-Salinity EOR at Interwell Scale, Endicott Field, Alaska
Authors: Seccombe Jim , Lager Arnaud , Jerauld Gary , Jhaveri Bharat , Buikema Todd , Bassler Sierra , Denis John , Webb Kevin , Cockin Andrew , Fueg Esther , Paskvan Frank 
Published: June 2014

Abstract
This paper describes the first comprehensive inter-well field trial of low-salinity EOR.
The objective of the trial was to demonstrate that reduced-salinity waterflooding works as well at inter-well distances as it does in corefloods and single well tests. The trial was designed to evaluate two risks: 1) whether mixing or other mechanisms prevent achievement of reduced-salinity improved recovery in the reservoir and 2) whether the adverse mobility ratio between the injected water and the oil bank causes viscous fingering – resulting in mobilized oil being left behind.
The demonstration was implemented in a single reservoir zone at the Endicott field (North Slope Alaska). The trial involves an injector and a producer 1040 feet apart. The producer was monitored for changes in watercut and ionic composition. In December 2007, produced saline water was injected to pre-flood the pattern until watercut was over 95%. Reduced-salinity water injection commenced June 2008. The associated EOR response was detected in the producer after three months. Data from a wellhead watercut meter and fluid samples from a test separator both revealed a clear drop in watercut, from 95% to 92%. The timing of the drop in watercut coincided with the breakthrough of reduced-salinity water at the producer.
Incremental reduced-salinity EOR oil recovery timing and volume matched behaviors observed in corefloods and single well tests. By May 2009, 1.3 pore volumes of reduced-salinity water had been injected. The incremental oil recovery is equal to 10% of the total pore volume in the swept area. Initial oil saturation at Endicott is 95%. In the pilot area, tertiary reduced-salinity waterflooding is expected to drop residual oil saturation from 41% to 28%, a 13 unit drop in residual oil.
The inter-well field trial demonstrates that the identified risks did not impact performance.
An elastic grid approach for fault uncertainty modelling and updating using the Ensemble Kalman filter.
Authors: Seiler A. , Aanonsen S. I. , Evensen G. , Lia O. 
Published: June 2014

Abstract
Uncertainties in the location, geometry and flow properties of faults can have a significant impact on the reservoir volumes, well planning, and production predictions. However, the reservoir geometry is usually fixed to a single interpretation in history-matching workflows due to the complexity of automatic updating of the structural framework and the related simulation grid.
In this paper, we propose a method to handle fault geometric uncertainties in the reservoir model and present an assisted history-matching workflow for updating the structural model with the Ensemble Kalman Filter (EnKF).
An ensemble of reservoir models, expressing explicitly the uncertainty in the throw and position of faults, is created. To avoid rebuilding the grid at each update step, we propose an elastic grid approach, where the geometry of a base-case reservoir grid is deformed to reflect the alternative structural realizations. The fault throw and fault position are considered as parameters for assisted history matching and are updated by sequential assimilation of production data using the EnKF.
The method is applied to synthetic examples and promising results are obtained. The result is an ensemble of history-matched structural models with reduced and quantified uncertainty in the fault position and throw. The elastic grid approach and the sequential processing of measurements in the EnKF provide a setting for fast and continuous model updating.
Hydrocarbon Potential of Devonian Sequence – A Case Study from Awali Field
Authors: Reddy Cheruku Bapu , Al-Ansari Yahya 
Published: June 2014

Abstract
Devonian Sequence consists of Jubah, Jauf and Tawil Formations and overlain unconformably by the clastics of the Permian Unayzah formation. Jubah is the younger formation in Devonian Sequence; its upper part has silicified sandstones, grey to black carbonaceous shales and coal with thin dolomitic shale/sand beds. Lower part has monotonous sequence of very fine to medium grained thick sandstone beds and subordinate grey siltstone, shale interbeds. Jauf formation underlies Jubah and overlies Tawil formation with conformable contacts. After deposition of Tawil, the shallow marine sands of Jauf formation were deposited over a broad shelf. Jauf reservoir is relatively cleanest and most porous of all pre-Unayzah reservoirs. Jauf is the main reservoir tested for gas in Awali field. Tawil is the older formation in Devonian and is mainly of sandstone with Shale intercalations. Depths of Devonian reservoirs of Awali field are in the range of 10,000 ft to 15,000 ft. Individual porous layers are 5-15 ft thick and alternate with tight well-cemented sandstones or shales. Gas shows were also reported in few drilled wells of Awali in Devonian reservoirs, but production testing was not carried out in these wells.
3D Seismic interpretation has been carried out by using 3D Re-processed PSDM volume. Integration of 3D seismic data and Geological information resulted in preparation of detailed subsurface structural and attribute maps at selected levels. Seismic attributes such as Frequency and Amplitude maps show some anomaly on Jubah, Jauf and Tawil levels, these are indirectly indicating the hydrocarbon reservoir development and also validated with the available Well's test results at Jauf level. Few potential stratigraphic and fault closure traps have also been identified in the flank of the Awali field.
The study resulted in identifying potential areas for exploration and supporting the ongoing exploration efforts in surrounding offshore areas for similar gas prospects.
Bringing New Life to Old Fields
Authors: Jaswadi Raam , Kasijatno Krisna , Jakeman Simon 
Published: June 2014

Abstract
PT Pertamina EP operates a large number of mature oil and gas fields across Indonesia, some of which have been producing for over 70 years. These fields are typically characterized by aging facilities, depleted reservoir pressures, extensive artificial lift, very high water cut, produced water management issues and sometimes a shortage of fuel gas supply, which creates enormous challenges for operators. In 2007 Pertamina embarked on a campaign of field reviews to try to identify to the true potential of the fields and reverse the production decline. The reviews followed Shell's ‘Producing the Limit’ business process and made use of technical expertise from both Pertamina and Shell.
Each review covered the complete field or structure from reservoir to export and used a multi-discipline team of staff with an intimate knowledge of the field, paired up with external ‘Technical Challengers’. The process provided a structured and systematic approach for mapping out and analyzing a field and helped to identify the maximum production that could be achieved under ideal conditions. A portfolio of opportunities (or projects) were then developed which would allow the current production to be increased towards that limit. Every review included a field visit to validate opportunities and to gather ideas from operations staff. Asset integrity and HSE issues were also addressed, since these would ultimately impact on field performance.
By end 2009 a total of thirteen reviews had been completed, which evaluated opportunities to more than double the production from the fields and identified new exploration and appraisal prospects which could extend the field life. The implementation programme has already generated a 37% increase in production potential. In addition, 30 best practices have been shared amongst the teams, several high risk asset integrity issues have been addressed and the multi-discipline teamwork has continued as a standard way of working.
Rock Typing in Gas Shales
Authors: Kale Sagar , Rai Chandra S. , Sondergeld Carl H. 
Published: June 2014

Abstract
Conventional methods of rock typing based on porosity-permeability cross-plots do not work in shales due to lack of dynamic range and difficulties involved in the direct measurements of most of the petrophysical parameters.. Here we present a methodology for rock typing in Barnett shale by integrating geological core description with porosity, total organic carbon (TOC), mineralogy and mercury injection capillary pressure which are relatively easy to measure.
Petrophysical measurements were made on 800 plugs obtained from almost 1600 feet of core recovered from four wells from Newark East field, TX.
Lithofacies of all the plugs were assigned using the stratigraphic columns developed by Singh (2008). From the petrophysical measurements, we observe three such groups or rock types. The three rock types so formed are termed as petrofacies ‘1’, ‘2’ and ‘3’. Each petrofacies was found to have distinct capillary pressure curve, and microstructure determined by ESEM. Cluster analysis of the petrophysica data set also indicates that rocks can be grouped into three clusters.
Petrofacies 1 represents the best reservoir rock with high porosity, TOC and quartz content and low calcite content whereas petrofacies 3 represents the worst reservoir rock with high calcite content and low porosity and TOC.
In order to verify that petrofacies 1 is indeed the best reservoir rock; we compared the thickness of the petrofacies with the overall gas production in two vertical wells. It is observed that the well with most continuous intervals of petrofacies 1, with minimum interference of petrofacies 2 and 3 over the perforated zone, produces better than the well with thick intervals of petrofacies 2 and 3 frequently separating petrofacies 1. This confirms that petrofacies 1 which is the best reservoir rock in a petrophysical sense is also a better gas producer.
Innovative Capillary Deliquification Safety System Resolves Liquid Loading Problems With a Cost-Effective Solution that Maximizes Production While Maintaining Well-Safety Requirements
Authors: Imbò Pasquale , Magnani Daniele , Di lorio Maurizio , Russotto Cesare , Tuckness Gene 
Published: June 2014

Abstract
Many mature gas wells worldwide have had to be shut-in due to water loading in the production string, which occurs when the liquid's hydrostatic column pressure equals that of the reservoir pressure, stopping production. Periodically injecting surfactant chemicals from surface has been tried but is only a temporary solution. Continuos injection of a downhole foaming agent can be used to lift the water and restore gas production. If an injection line is not part of the completion string, an external injection line can be installed either with a rig workover or a rigless through-tubing installation. The first solution requires significant rig expense, and the second can cause loss of downhole safety-valve functionality. A more cost-effective, safer problem resolution method was needed.
This paper describes the first ENI field trial of a Capillary Deliquification Safety System that can be retrofitted into existing wells with rigless intervention to quickly reinstate production. This method maintains safety valve functionality and eliminates an expensive well workover. The installation equipment includes a modified wireline-retrievable surface-controlled sub-surface safety valve (WR-SCSSV) with capillary tubing attached below. The injection method operates via the control system for the WR-SCSSV. The installation, which uses the existing control line of the safety valve to inject chemicals, does not require wellhead modification.
The trial installation of the new system took place in a shut-in well in a Barbara offshore field in the Adriatic Sea. The trial showed that the system could provide a cost-effective alternative to well workovers and occasional surfactant treatments and will significantly increase hydrocarbon recovery from the reservoir while maintaining the well's safety level.
Improving Progressing-Cavity-Pump Performance Through Automation and Surveillance
Authors: Woolsey Kelly A. 
Published: June 2014

Summary
To extend the run life of the pump while producing all available fluid is the goal of all progressing-cavity-pump (PCP) operators. The primary challenge is to do so without starving the pump and causing damage to the stator. The petroleum industry has been searching for years to find a reliable way to control PCPs for pumpoff. Several methods have been used, from monitoring torque to manual fluid levels. To date, none of these have been commercially successful. A method for controlling these wells has been developed combining wedge flowmeter technology and microprocessor control of both electric motors using variable-frequency drives and hydraulic motors using proportional control valves. This method has proved to be accurate and reliable, extending the run life while producing all available fluids.
Combining this automated technology at the well with a Web-based system that feeds back real-time data to a dedicated surface-control-and-data-acquisition (SCADA) host allows PCP technical experts to diagnose problems and operators to respond quickly to changing well conditions.
This presentation discusses the advances in automation and optimization of PCPs. The method will be explained, and field-study results showing actual well tests will be presented.