bluuebunny/crossref_metadata_2025 huggingface dataset:
Managing HSE Risk in Harsh Environment
Authors: Yusoff Nor Hashim , Yusof Mohd Radzuan
Published: June 2014

PETRONAS Carigali Sdn Bhd (PETRONAS Carigali) is a fully-owned subsidiary of Petroleum Nasional Berhad (PETRONAS), a Malaysian National Oil Company (NOC). PETRONAS was incorporated on 17 August 1974, while its E&P arm, PETRONAS Carigali, was incorporated on 11 May 1978. PETRONAS was originally formed with the intent to increase Malaysian participation in the E&P industry in the country.

However, PETRONAS has been actively expanding its activities beyond Domestic arena, especially in the E&P sector. PETRONAS, through its E&P arm PETRONAS Carigali, has expanded its business to more than 30 countries in South East Asia, Middle Asia, Middle East, Africa and America. After being an oil and gas player for just more than 30 years, PETRONAS Carigali has moved from Domestic Player to International since 1990.

Being a global player, knowledge and experience is crucial in ensuring successful ventures. In this respect, PETRONAS being a ‘young’ Company compared to other major global players who have been in existence for more than 100 years, has a proven track record of successful ventures including being listed in Fortune 500 as well as obtaining excellent HSE performance.
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

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

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

Understanding 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

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

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

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

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

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

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

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

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

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.
Experimental Optimization of Catalytic Process In Situ for Heavy-Oil and Bitumen Upgrading
Authors: Shah Amjad A. , Fishwick Robert P. , Leeke Gary A. , Wood Joseph , Rigby Sean P. , Greaves Malcolm
Published: June 2014

The worldwide conventional crude-oil demand is on the rise, and because of the rising prices, unconventional oils are becoming more economically attractive to extract and refine. However, technological innovation is needed if heavier oil supplies are to be exploited further. Toe-to-heel air injection (THAI) and its catalytic add-on processes (CAPRI) combine in-situ combustion with catalytic upgrading using an annular catalyst packed around the horizontal producer well. These techniques offer potentially higher recovery levels and lower environmental impact than alternative technologies (e.g., steam-based techniques). An experimental study is reported concerning the optimization of catalyst type and operating conditions for use in the THAI-CAPRI process. The feed oil was supplied from the Whitesands THAI-pilot trial. Experiments were carried out using microreactors containing 10 g of catalyst, with oil flow of 1 mL/min and gas flow of 0.5 L/min, under different temperatures, pressures, and gas environments. Catalysts tested included alumina-supported CoMo, NiMo, and ZnO/CuO. It was found that there was a trade-off in operation temperature between upgrading performance and catalyst lifetime. At a pressure of 20 bar, operation at 500°C led to an average of 6.1°API upgrading of THAI oil to 18.9°API, but catalyst lifetime was limited to 1.5 hours. Operation at 420°C was found to be a suitable compromise, with upgrading by an average of 1.6°API, and sometimes up to 3°API, with catalyst lifetime extended to 77.5 hours. Coke deposition occurred within the first few hours of the reaction, such that the catalyst pore space became blocked. However, upgrading continued, suggesting that thermal reactions or reactions catalysed by hydrogen transfer from the coke itself play a part in the upgrading reaction mechanism. The CAPRI process was relatively insensitive to changes in reaction-gas medium, gas-flow rate, and pressure, suggesting that the dissolution of hydrogen or methane from the gas phase does not play a key role in the upgrading reactions. By careful control of the temperature and oil-flow rate in the in-situ CAPRI process, additional upgrading compared with the THAI process alone may be effected, resulting in a more-valuable produced oil, which is easier to transport.
Analyzing Production Data From Unconventional Gas Reservoirs With Linear Flow and Apparent Skin
Authors: Nobakht Morteza , Mattar Louis
Published: June 2014

Many horizontal wells with multiple fractures producing from unconventional gas reservoirs have been observed to exhibit linear flow. Often it is the only flow regime, and it can last several years. Classically, this flow regime is characterized by a half slope on type curves when there is no skin effect. However, most of the time, a skin effect is observed in these wells (caused by flow convergence or finite conductivity in the fractures).

The presence of skin changes the shape of data points when plotted on log-log scales, and this can have a huge effect on the interpretation when using type curves. For example, a well with purely linear flow and with skin in a reservoir that is infinite acting may appear like and be interpreted as a finite-acting reservoir simply because of the skin effect.

This paper discusses different methods that can be used to eliminate the misinterpretation caused by the presence of skin when analyzing linear flow by use of type curves. First, it is shown that among all the derivative and integral functions that are currently used, only well-test-style semilog derivative (DER) and pressure integral-derivative are not affected by the skin. However, these two functions have other issues that usually make them unfit for use in production-data analysis. DER is noisy most of the time, and the process of integration often introduces errors at early times that can significantly distort the shape of the pressure integral-derivative. Therefore, an easier method is presented to analyze the production data from shale gas reservoirs with extended periods of linear flow and significant skin. This method uses the square-root-of-time plot to remove the apparent skin effect from the data. Then, the data (excluding skin) are used for type-curve analysis. This simple procedure prevents potentially significant misinterpretation.
First-Contact-Miscible, Vaporizing- and Condensing-Gas Drive Processes in a Channeling Heterogeneity System
Authors: Al Wahaibi Y. M. , Al Hadhrami A. K.
Published: June 2014

Experimentally measured recoveries, gas cuts and residual saturations as well as the visual observations were used to quantify the effects of channeling heterogeneity system on efficiency and gas/oil nonequilibrium of first- and multi-contact miscible (MCM) displacements. These experiments are the first of their kind as they have enabled a direct insight into the mechanisms of gas/oil flow occurring within such type of heterogeneities, and particularly have provided a firmer understanding of the MCM processes.

The key finding in this work is the fact that the produced fluids in all MCM experiments were not in compositional equilibrium. The effect of channeling heterogeneity was to lower mass transfer between oil and MCM gas phases throughout the porous medium as a whole, thereby driving the system to be more sub-miscible and as such reducing the sweep and increasing the bypassing. These results were also reflected in the increase in nonequilibrium between gas and oil phases. This work has proved that the channeling heterogeneities, even with small permeability contrast, can distort first- and multi-contact miscible displacement patterns considerably.

Additionally, the results suggested that the performance of MCM processes decrease significantly with the increase in injection rate. This was probably due to an interplay between capillary and viscous forces in the heterogeneous model causing the gas at highest rate to flow faster into the high permeability stripe, and therefore resulting in a larger transition zone, shorter miscibility region, higher nonequilibrium and hence a lesser efficient flood.

This study has important implications for the correct interpretation of core data, and for scale-up processes to reservoir scale, particularly for handling gas/oil nonequilibrium when modelling MCM displacements.
Integrated Geodynamic Monitoring and Risk Assessment of Occurrence of Seismic Deformation Processes Related to Development of Raw Hydrocarbon Deposits
Authors: Shevelyova A..
Published: June 2014

The Karachaganak field is a large onshore gas-oil-condensate accumulation with initial hydrocarbons in place of approximately 9 billion barrels of condensate and more than 45 trillion cubic feet of gas. The Karachaganak structure is a carbonate massif that comprises a heterogeneous reef and platform carbonate complex measuring 30 km by 15 km.

Geodynamic events of natural and man-induced genesis occurring during the development of hydrocarbon fields attract considerable attention from both the general public and engineering specialists alike. This paper highlights the necessity of geodynamic monitoring in the course of a hydrocarbon field development and describes the status of geodynamic monitoring in the Karachaganak field located in West Kazakhstan Oblast.

Lack of control over geodynamic events of natural and man-induced genesis can lead to irreversible consequences (induced earthquakes in USA, Canada and other countries), that can be damaging to the environment, and costly to remediate. Identification, prognosis and prevention of such consequences are fundamental tasks of the geodynamic monitoring in the course of development of hydrocarbon fields. Therefore, the task of monitoring geodynamic processes during the development of oil and gas fields draws special attention from operating companies and government authorities.

Implementation of geodynamic monitoring prior to commencement of and during commercial field development is a mandatory requirement of the RoK legislation. A primary purpose of geodynamic monitoring is to ensure environmental safety by taking necessary measures to mitigate and prevent a risk of occurrence of uncontrolled events associated with geodynamic processes during and after field development.

In Karachaganak field the monitoring over geodynamic processes began in 2002 by initiating a local seismological monitoring program which continued until the end of 2007. In 2008 a programme of integrated geodynamic monitoring was developed. Implementation of the programme, which envisages application of such methods as levelling, gravimetric and GPS surveys, and seismological monitoring, will allow the operator to thoroughly study geodynamic processes in Karachaganak field.

In June of 2009 a benchmark survey was conducted, and as more data from repeat surveys becomes available, it will be possible to investigate patterns and temporal development of geodynamic processes such as an activation of faults, compaction and lateral displacements of rock masses, surface subsidence, and seismicity.
Application of Artificial Intelligent Systems in ROP Optimization: A Case Study in Shadegan Oil Field
Authors: Bataee M.. , Mohseni S..
Published: June 2014

According to the field data, there are several methods to reduce the drilling cost of other wells. One of these methods is the optimization of drilling parameters to obtain the maximum available ROP. Considering the geology and rock mechanic parameters, each part of well has different recommended parameters.

There are too many parameters affecting in rate of penetration like hole cleaning (including drillstring rotation speed, mud rheology, weight on bit and floundering phenomena), tooth wear, formation hardness (including depth and kind of formation), differential pressure (including mud weight) and etc. Therefore, developing a logical relationship among them to assist in proper ROP selection is extremely necessary and complicated though. In such a case, Artificial Neural Networks (ANNs) is proven to be helpful in recognizing complex connection between these variables. Genetic Algorithm (GA), as a class of optimizing methods for the complex functions, is applied to help ROP optimization and its related drilling parameters. Optimization program will optimize drilling parameters which will be used in future works and also leads us to proper time estimation. The present study is predicting the proper penetration rate, optimizing the drilling parameters, estimating the drilling time of well and eventually reducing the drilling cost for future wells.
Asset Integrity Key Performance Indicators - A Cross Industry Approach
Authors: Paterson Robert
Published: June 2014

This paper follows the identification, development and evolution of two, asset integrity related key performance indicators (KPI) for the UK offshore industry. Both indicators relate to differing aspects of the status and condition of safety critical plant and equipment on the installation. Data covering 99% of UKCS offshore installations since the beginning of 2008 is covered. Next steps for further development of these KPIs are outlined, together with key lessons for others wishing to set up and develop other whole industry performance indicators
Proper Design of Polymer-Based In-Situ Gelled Acids to Improve Carbonate Reservoir Productivity
Authors: Gomaa Ahmed M.
Published: June 2014

Lab test of polymer-based in-situ gelled acids reveal that polymer and other additives separate out of the acid when these acids are prepared in high salinity water. In coreflood tests, in-situ gelled acid formed a gel inside 20". long core samples, and the acid changed its direction several times. Unexpectantly, the core's permeability was reduced at low shear rate. Wormhole length increased as the shear rate was increased, while the diameter of wormhole increased as the acid cumulative injected volume was increased. CT scan indicated the presence of gel residue inside the and around the worm hole. Gel residue increased at low shear rates. Material balance on the cross-linker indicated that a significant amount of the crosslinker was retained in the core.

Based on the results obtained from this study the in-situ gelled acids should be used only at low HCl concentrations (5 wt% HCl). Acid should be prepared in low salinity water. Acid injection rate should be determined based on the expected shear rate in the formation. A core flood experiment is recommended to confirm optimum injected rate. Flow back the well to minimize the residual gel inside the formation. The data obtained in our study can be used as a guideline for injection rate selection.
Interfacial Areas and Immiscible Fluid Structures of Oil and Water in Oil-Wet and Water-Wet Porous Media
Authors: Landry Christopher James
Published: June 2014

The objective of this study is to obtain quantitative evidence of pore-scale immiscible fluid distribution in oil-wet and water wet porous media using x-ray computed microtomography. Temporal and spatial saturation profiles, as well as surface and interfacial areas are thoroughly analyzed through cycles of drainage and imbibition using samples with different wetting characteristics but similar pore structures. Furthermore, the population of individual immiscible fluid structures (blobs') is also evaluated. The specific non-wetting phase surface areas of both porous media are found to be in close correlation with the specific solid surface area. On the other hand, the differing wetting strengths of the two porous media affects the fluid fluid interface, and thus the specific meniscus interfacial area of the two porous media. The specific meniscus interfacial area trends towards a maximum at wetting phase saturations of 0.35–0.55 for both porous media. The saturation of the maximum specific meniscus interfacial area is that of the greatest fluid-fluid interaction. The differences in wetting characteristics are also apparent in the blob populations. The number of blobs in the oil-wet porous media is three times greater than that of the water-wet porous media at similar saturations; the increase in population is due to the increase in the amount of smaller blobs being found in the more weakly-wetting oil-wet porous media, a result of lacking wetting-phase dominance in the smaller pore spaces. The surface areas of individual blobs as a function of the individual blob volumes are found to closely agree with that of a sphere at blob volumes below the minimum individual grain volume, and with the specific pore space surface area above this volume. These results show how the pore space geometry, wettability and saturation history influence the distribution of immiscible fluids within the pore space; these general observations can be a powerful resource for the improvement of multiphase fluid flow property prediction, properties such as relative permeability and capillary pressure.
Development of a Predictive Model for Carbon Dioxide Sequestration in Deep Saline Carbonate Aquifers
Authors: ANBAR Sultan
Published: June 2014

Increase in CO2 concentration in the atmosphere is the widespread concern due to its global warming effect. CO2injection into deep saline aquifers is one of the preferable ways to mitigate the CO2 emission since CO2 is in supercritical state and larger volumes of CO2 can be stored due to its high density. Several numerical simulations are needed before injection to determine the storage capacity of a saline aquifer. Since numerical simulations are very expensive and time consuming, developing a predictive model can be very useful to quick estimation of CO2storage capacity of a deep saline aquifer.

To create a predictive model, ranges and limits of rock properties (porosity, permeability, vertical to horizontal permeability ratio), fluid properties (irreducible water saturation, gas permeability end point, Corey water and gas exponents), reaction properties (forward and backward reaction rates) and reservoir properties (depth, pressure gradient, temperature gradient, formation dip angle, salinity), diffusion coefficient and Kozeny-Carman Coefficient that affect the CO2 storage capacity are determined from published literature data. Other parameters such as pore volume compressibility and density of brine are calculated from correlations. To cover all possibilities, Latin Hypercube Space Filling Design is used to construct 100 simulations developed using CMG STARS for 300 years of CO2 injection. By using least squares method, a linear correlation with a correlation coefficient 0.81 is found to calculate CO2 storage capacity of the deep saline carbonate aquifers by using aforementioned simulation variables. Numerical dispersion effects have been considered by increasing the grid dimensions. It has been found that correlation coefficient decreased to 0.78 when the grid size was increased from 250 ft to 750 ft. The sensitivity analyses showed that the most important parameter that affects CO2 storage capacity is depth since the pressure difference between formation pressure and fracture pressure increases with depth. It was observed that most of the gas (up to 90%) injected into the aquifer formation dissolves into the formation water and negligible amount of CO2 reacts with carbonate. This result is in accord with sensitivity analyses as the variables affecting the solubility of CO2 in brine have greater affect on storage capacity of aquifers. Dimensionless linear and nonlinear predictive models were constructed to estimate the CO2 storage capacity of a deep saline carbonate aquifer and it was found that the best dimensionless predictive model is a linear model that is independent of bulk volume of the aquifer.
Pulse Testing for Enhanced Reservoir Characterization of the EOR Pilot Area in Mangala Field
Authors: Jha Manish Kumar , Pandey Amitabh , Tandon Rohit , Beliveau Dennis
Published: June 2014

Abstract and Introduction

Mangala is a large oilfield in northwestern India containing significant volumes of moderately viscous paraffinic crude oil. The base field development plan is a hot waterflood, but due to the adverse mobility ratio between injected water and in situ oil, large volumes of water will be produced overlife along with the oil. As a result, the Operator has been examining EOR options since the field discovery in 2004, with aqueous-based chemical processes being the preferred way forward.

Oil production began in August 2009, quickly followed by startup of the water injection system in January 2010. Currently, the field is producing 125,000 bopd with injection of 140,000 bwpd. Since the Operator envisages early field-scale implementation of chemical EOR, a closely-spaced eight-well polymer-ASP flood pilot was constructed during 2010. Pilot water injection began in December 2010, less than a year after the field-scale waterflood startup.

The foundation for the analyses of any EOR pilot is appropriate reservoir characterization, and all efforts are being made to ensure that right data is collected in the Mangala EOR pilot. A key aspect of the reservoir characterization program involves multi-well pulse tests which are described in this article.
Experimental Investigation of In-Situ Combustion at Low Air Fluxes
Authors: Alamatsaz Alireza , Moore R. Gordon , Mehta Sudarshan A. , Ursenbach Matthew G.
Published: June 2014

The oil industry has inherited a mixed history of success and failure of application of air injection as an enhanced-oil-recovery method. Close scrutiny of these projects shows that in order to conduct a successful in-situ-combustion-oil-recovery project, sustained propagation of the combustion front within the reservoirs is necessary. Sufficient air must be supplied to maintain the propagating combustion front in the desired bond-scission (carbon-oxide-forming) mode, otherwise unfavourable oxygen addition [i.e., low-temperature-oxidation (LTO) reactions] will consume oxygen and immobilize oil. When this happens, the combustion process is deemed to be exhausted.

Quantification of the minimum air flux required for sustaining combustion-zone propagation is needed to properly match the capacity of the air-injection facility to the volume of the reservoir that is to be swept by the thermal zone. Undersizing the air-injection capacity causes the in-situ-combustion process to become inefficient at a point when only a small portion of the reservoir has been "burned."

One-dimensional combustion tubes (CTs) are conventionally used to obtain important combustion parameters required for designing an air-injection project. Because of the high heat capacity of laboratory equipment designed for elevated-temperature and -pressure operation, oxygen addition or LTO reactions are promoted by the heat transfer through the core-holder walls when the laboratory tests are performed at low air-injection rates. Therefore, when operated at elevated pressures, the CTs are unable to operate at the low air fluxes required to establish the minimum possible air-injection flux while maintaining the combustion reactions in an effective mode.

To address this issue, a state-of-the-art combustion cell was conceived and used as a way of addressing the previously mentioned constraints associated with high-pressure 1D CTs. A conical combustion-cell design was built because it enables continuous air-flux reductions without having to adjust the air-injection rate. The heater control strategy was also modified in order to address the lag-lead operation often used for 1D CTs. To date, the unit has operated at air fluxes down to 3 std m3/m2•h.

The experimental work described in this paper provides insight into the limitations in laboratory investigations of in-situ combustion and the expected behaviour of field applications of the in-situ-combustion process.
Acoustic-Wave-Testing System for Monitoring the Vapour Chamber in Vapour-Extraction Process
Authors: Zhou Wenjin , Paranjape Raman , Asghari Koorosh
Published: June 2014

The acoustic-wave-detection system is considered a nondestructive monitoring system to estimate distances by measuring the time-of-flight of an ultrasonic wave. In this paper, a comprehensive experimental study was conducted to investigate the feasibility of the acoustic-wave-detection system in monitoring the shape and position of the gas phase in the vapour-extraction (VAPEX) process. For this purpose, various stages of vapour-chamber evolution in the VAPEX process were simulated experimentally by changing the shape of air balloons buried in simulated porous media in a laboratory-scale model. Then, an array of ultrasound transducers and receivers was used to measure time of flight at different stages of the vapour-chamber growth. Finally, the collected data were fed into a signal-processing program developed in this study to determine the shape of the vapour chamber. Conducted analysis in this study includes sound-speed testing in different porous media, signal-attenuation tests in different porous media, imaging of different simulated vapour chambers in different porous media, and acquisition and analysis experiments. Results show that acoustic-wave detection can be used for accurate mapping of the position and shape of the vapour chamber in the studied process. Monitoring the shape and growth of the vapour chamber provides valuable information for optimizing oil production in order to maximize oil recovery. The proposed methodology is able to identify acoustic anomalies in a porous medium in the laboratory.