bluuebunny/crossref_metadata_2025 huggingface dataset:
Dendrimers and Dendritic Polymers - Application for Superior and Intelligent Fluid Development for Oil and Gas Field Applications
Authors: Amanullah Md.
Published: December 2013

Application of dendrimers and dendritic polymers in oil and gas field fluid formulation can revolutionise the fluid properties due to the unique physical, chemical and biological characteristics of these materials. The ability to synthesize tailor made dendrimer products with desirable functional behaviour also highlights the potential application of dendrimers in smart and intelligent fluid design for oil and gas field application. The large number of monomer units associated with dendrimer core has the potential to add several functional groups of same ionic nature or different ionic natures to fulfil certain technical tasks for a particular application. Custom made dendrimer-based additives that are insensitive to temperature, salinity, pH, solids concentration, cement and lime contamination may lead to the development of a multiple contaminant tolerant drilling mud system for trouble free drilling operation in variable borehole environments. Due to superior physical, chemical, electrical and mechanical properties of dendrimers and dendritic polymers, and also the synthesis of dendrimers that are capable to respond intelligently according to down hole conditions can provide instantaneous solution to various drilling problems.

The internal cavities within the dendrimer structures can be used to store desirable chemicals, enzymes, surfactants, etc to trigger appropriate interactions on-demand at bottom hole condition to negate, neutralize or reduce the unwanted changes in drilling, drill-in, completion, cleaning, stimulation, fracturing, etc fluids. The three dimensional spherical configurations of nano-sized dendrimers with high specific surface area can also allow the attachment of multiple functional groups at the terminals to accomplish different functional tasks. Dendrimers with the ability to trigger on-demand interaction by releasing stored chemicals, enzymes or surfactant stored in the cavities can play a pivotal role in developing an intelligent drilling fluid system to provide instantaneous solution to down hole problems. Due to nano-scale dimension, dendrimers may provide effective external and internal inhibition to reactive shale surfaces leading to long-term stabilization of reactive shales. The tiny size and high surface area of dendritic materials will also provide superior fluid properties at a drastically reduced additive concentration.

Dendrimers and dendritic polymers with high thermal stability and affinity to acid gases such as H2S and CO2 will help overcome the technical challenges of geothermal and sour gas drilling operations for a safe, risk-free and economic drilling operation. This paper describes some applications of emerging dendrimers and dendritic polymer-based additives in the development of high performance drilling and drill-in, completion, stimulation, etc fluids for trouble-free drilling, completion and production operations in challenging environments.
Application of a Newly Developed Workflow to Design and Optimize MRC and Smart Well Completions
Authors: Shenawi S. , Hidayat W. , Shammari M. , Nasser K. , Faleh A. , Nahdi U. , Ghuwaidi Y. , Mekki N.
Published: December 2013

It is challenging to find optimal well placement and completion design for maximum reservoir contact (MRC) wells in heterogeneous oil and gas reservoirs. Saudi Aramco initiated a new workflow in collaboration with a service company, to achieve such objectives based on integrated software packages of Petrel™ and Saudi Aramco’s POWERS™ simulator. This workflow can conduct simulation runs optimizing well architecture, smart completions with inflow control devices (ICD/ICV), lateral and vertical shift of the well, to obtain maximum oil and gas recovery applying sensitivity and optimization algorithms. The new workflow proved to have robust functionality and provided significant cost savings and optimal oil and gas recovery.

Three case studies are discussed in this paper. The new workflow assessed the proposed side track and concluded that it was not a good option due to faster water influx from the west flank. This workflow moved the side track lateral to 207 meters to the east and designed to equip the well with ICD and blank pipes. The optimized side track provided 50% more oil recovery than the well that was not moved.

The second case was to propose the best location and complex well design for a dual-lateral maintain potential well. The most sensitive parameters were moving the well to the north and vertical locations, motherbore’s length and oil rates. Shifting dual laterals to 750 meters north, optimized ICDs, and 1750-meter motherbore length provided double the cumulative oil production than the single well manually designed and completed.

The third case discusses a tri-lateral well optimization for an oil field that is under development. Based on the sensitivity analysis and shifting well locations have the most significant impact to provide higher oil recovery and delayed water breakthrough for several years.
Thru-Tubing Inflatable Straddle Packer Assembly Enables Selective Treatment of Multiple Zones and Improves Productivity
Authors: Kothiyal M. D. , Parasher A. , Qutob A. H. , Cooper R. J. , Forsyth G. R.
Published: December 2013

The subject well is an onshore oil producer located in Cairn Energy India’s Rajasthan block. The well had stratified sand sections completed with 4-inch inflow control device (ICD) screens and isolated by swellable packer assemblies. The well was put into production at a rate of approximately 1,000 bopd; however, due to formation damage – notably paraffin and scale - the well could not sustain production and eventually ceased.

Our objective was to selectively stimulate 15 ICDs using coiled tubing. The well had a minimum restriction and a larger setting diameter which warranted the usage of coiled tubing deployed inflatable straddle packer system. This enabled passage through the restriction and setting in the larger outer diameter to selectively treat each zone by mechanically diverting the stimulation fluid.

The challenge was significant. Multiple zones required treatment in a single run by performing 15 multi-settings, maintaining seal integrity following each set, and returning the tool to its original outer diameter for retrieval. The well was deviated at 74 degree which challenged accessibility.

The assembly was run successfully and managed to selectively stimulate all required zones in one trip. Using this application, we confirmed that all treatment fluid was effectively sealed and treated by diverting the treatment fluid directly into the required zone, preventing more permeable sections absorbing most of the fluid, and ensuring the treatment chemicals were used in a cost effective manner. The single coiled tubing run avoided multiple runs to isolate sections using plugs. The well subsequently began to flow once lifted with nitrogen, positively indicating that the ICDs were effectively cleaned and the zones successfully treated.

This case demonstrates the innovative use of thru-tubing wellbore isolation techniques to effectively enhance production in wells with challenging configurations and operating parameters. This study further paves the way for similar interventions in wells with similar characteristics.
Steady-State Permeability Measurements on Intact Shale Samples at Reservoir Conditions - Effect of Stress, Temperature, Pressure, and Type of Gas
Authors: Sinha S. , Braun E. M. , Determan M. D. , Passey Q. R. , Leonardi S. A. , Boros J. A. , Wood A. C. , Zirkle T. , Kudva R. A.
Published: December 2013

Gas shales have gained significant attention in recent years as a source of natural gas, resulting in significant focus on storage and flow mechanisms in these rocks. The permeability of shale reservoirs is a key control that determines the producibility and profitability of the resource. In contrast to conventional reservoir rocks, gas shales have significant organic content and, often, most of the pores are in the organic matter. Furthermore, most pores are in the 1–100 nanometer size range, and gas can be stored in these pores as sorbed gas as well as free gas, which has raised concerns such as deviation of the flow mechanism from Darcy flow, and the effect of sorption on permeability in shales. The common industry practice of measuring permeability using crushed rock samples and helium as test gas at room conditions has been found to have a number of shortcomings, including inconsistent results reported by different laboratories using such methods. In this paper we present the results of steady-state permeability measurements on shale samples conducted at reservoir conditions, and demonstrate the effect of stress, pressure, temperature, sorption, and type of gas utilized for measuring permeability of intact shale samples.

The results presented in this paper show that net stress, pore pressure, and temperature have strong effects on permeability of shales. Additionally, we show that the type of gas utilized for measurements, and sorption phenomenon can have a significant influence on the measured permeability, particularly for organic rich samples such as gas shales. We also demonstrate through examination of Klinkenberg flow model, that currently, with the exception of the effect of pressure on permeability, no existing model accurately predicts the effects of other factors such as temperature and type of gas on permeability of shale samples in the absence of actual experimental measurements. This paper documents that there may be significant errors associated with measurements that are conducted at room conditions using non-reservoir or non-sorbing gas, and accurate permeability measurements require tests to be conducted at conditions that are close to the in-situ conditions. Accurate permeability measurements conducted at reservoir conditions enable superior characterization, supporting sound business decisions in the development phase of a project, and more accurate production forecasting in the production phase.
Evaluation of the Pressure Drop due to Multi Phase Flow in Horizontal Pipes Using Fuzzy Logic and Neural Networks
Authors: Attia M. , Mahmoud M. A. , Abdulraheem A. , Al-Neaim S. A.
Published: December 2013

One of the most important parameters affecting flow rate in oil producing wells is the pressure drop across the surface flow-lines. The pressure drop calculation in multiphase flow is very complicated due to the empirical nature of the correlations used and the high variation in gas and liquid hold up especially in hilly terrain and rough environment that will complicate the flow regime and make negative impact on well productivity. Scientists came up with two main approaches: empirical/experimental flow correlations and mechanistic models to overcome this difficulty. These two approaches are applicable within certain conditions where their accuracy in pressure drop prediction degrades outside their design boundary ranges.

The raising popularity of Artificial Intelligence (AI) techniques during the past two decades proved that AI can be an alternative solution to many of the problems where physics and classic statistics fail to provide satisfactory solutions. This paper describes the utilization of Fuzzy Logic and Neural Networks, which is one of the industry AI techniques in predicting the multiphase flow pressure drop in surface pipeline for oil fields using real testing data collected from oil fields. More than 240 published real well testing data were used in constructing the model.

After filtering the data and building the model, the newly developed AI model was the best method to predict the multiphase flow pressure drop. Prosper software was used to confirm the validity of the AI methods over the other existing correlations. The final results confirmed that Adaptive Neuro-Fuzzy Inference System (ANFIS) is more accurate than all the used correlations and Neural Networks. The ANFIS model resulted in .4% absolute average error compared to a range of 17.5% – 64.57 % for the compared correlations.
Sampling While Drilling Goes Where Wireline Can’t: Case Studies Illustrating Wireline Quality Measurements in Challenging Borehole Environments
Authors: Sanchez Francisco Galvan
Published: December 2013

In the early 2000s, formation pressure while-drilling tools were introduced that can obtain formation pressure data, even in highly deviated wells and extended-reach drilling. In the past two years, this LWD technology has evolved with the addition of downhole fluid sampling and fluid analysis. LWD sampling and testing is now performed in challenging environments that cannot be performed with wireline tools such as horizontal or highly deviated wells. The limitations of wireline deployment in these wells are because of the cumulative frictional resistance of the wireline, the toolstring components and the borehole where it is run. Although several technologies exist to mitigate the risks, such as fly wheels, wireline tractors or pipe-conveyed options, operators prefer to eliminate the risks and costs associated with them by utilizing LWD technology.

The first part of this paper describes the new sampling and testing service that was designed for the LWD environment. The service has several closed-loop control systems for pressure testing, mobility determination and pumping during sampling and cleanup operations. In-situ fluid analysis is achieved with sensors that measure optical refractive index, sound speed, density and viscosity. Downhole fluid samples are retrieved with single-phase tank technology.

The second part of this paper details case studies of field tests that were performed for a major operator in Trinidad and an IOC in the Netherlands. In Trinidad, the service successfully performed pressure testing, real-time fluid analysis and recovered three single-phase samples while drilling a 300ft section at a 70° deviation. On a dedicated logging run in the Netherlands, the service first accurately took 25 formation pressure points and clearly identified three distinct gradients. The customer targeted four zones of interest and acquired 11 samples: six single-phase samples in the oil zone, three single- phase samples in the water zone and three single-phase samples in the gas zone. The pressure testing and sampling was executed in a 1,307 m tangent section at a 73° inclination. The service was utilized to determine the presence of moveable fluids in the reservoir of a horizontal development well for a customer in Norway. The tool was positioned at a sampling station with a mobility of 1.8 mD/cP; after nearly five hours of pumpout at that station, it successfully acquired the first sample, and after another four hours at the same station, the tool acquired the second sample.

In both cases, the LWD sampling and testing service was chosen over wireline to mitigate the risks of sticking during the sampling and pressure testing operation. These field tests demonstrated that the LWD service is capable of taking wireline-quality measurements in extremely challenging borehole environments.
Advanced Workflow for 3-D Geological Modeling of a Complex Giant Field, Greater Burgan, Kuwait
Authors: Filak Jean-Michel , Van Lint Julien , Ali Farida , Ma Eddie , Al-Houti Reham
Published: December 2013

The Burgan-Wara formations from Southeast Kuwait (Greater Burgan field) constitute the largest known siliciclastic oil reservoir on earth. A specific workflow combining geological, geophysical and reservoir engineering techniques was developed to build a fully integrated and representative geomodel of the field.

The sedimentology and stratigraphy were here reviewed in terms of depositional environment and lateral stratigraphic correlation. The variability inherent to the depositional style leads to a complex reservoir scheme. Lower Burgan is dominated by stacked braided channels representing homogeneous, high quality reservoirs. Higher in the stratigraphy, lateral facies variability and heterogeneities are observed in tidal dominated units. Mud dominated units occur within the Upper Burgan and Lower Wara formations and provide good sealing capacities. Small, laterally strongly variable and heterogeneous fluvio-tidal dominated units are representative of the Upper Wara Formation.

A 3D geological model of more than 900 million cells was built, based on the new structural and stratigraphic framework interpretations to capture the complexity of the Burgan Field reservoirs. Rock-types were defined, based on more than 900 well logs and core petrophysical properties measurements. The seismic reservoir characterization, focused on inversion techniques and calibrated with the newly defined rock-types provided crucial information on sandstone proportions distribution, especially in areas with lower well control.

The first attempt to simulate, at high resolution, the largest siliciclastic oil field in the world provides a comprehensive way to understand the field heterogeneities and behavior. The updated geological model, based on new interpretations allowed characterizing the major reservoir heterogeneities and has significant impact on the reservoir management of this giant field.
Application of the Gas Handlers in KOC
Authors: Rahime Farouk , Sakr Karim , Areekat Moossa , Suryadi Richard
Published: December 2013

This paper presents the experiences of using multi-vane gas handling pump stage (MVP) at the RQ/AD field in electric submersible pump (ESP) completed wells that have gas production. KOC repeatedly experienced short run times due to the gas issue including after the switching off or tripping the ESP. Upon restart, the gas damaged the ESP, causing premature failure.

The MVP pump is an industry first to overcome this issue that has plagued ESP users for years. The new technology tool is designed to enhance the run time of ESPs in gassy wells.

The MVP features a unique, patented impeller design that enables the pump to continually operate while producing substantial lift in fluid conditions up to 70% free gas, subject to the constraints of the Turpin Correlation. The MVP pump technology was extensively tested in high pressure gas test loop; this unique, highly instrumented state-of-the-art testing facility is the only one of its kind in the industry and is used to aid the design development and evaluation of gas handling technology. MVP can be used alone or employed as a charge pump in a standard ESP system. MVP can be combined with the BH GM Series gas separator for applications with greater than 90% free gas.

The BH MVP was used in KOC specifically (RQ/AD) field in Kuwait; this paper outlines the improvements seen as a result of utilizing the MVP technology.
Coiled Tubing As A Sucker Rod As Well As Production String In Dual Zone Completion
Authors: Parekh-Pandit Rathin P. , Desai-Pandit Krupesh
Published: December 2013

Technological advances in coiled tubing, Coiled Tubing handling equipment, and application techniques have provided new opportunities for the effective, economic use of Coiled Tubing in various fields of petroleum industry. The technology is still in the process of testing its boundaries and limitations. However, this is a necessary phase in the learning curve. Probably the most logical approach is to consider the market or application niches best suited to coiled tubing drilling technology.

Evolution of the coiled tubing Production process is one of the most exciting and fastest growing sections of the coiled tubing industry. In Dual zone completion, production is conventionally carried out using parallel tubing string completion or tubing annulus completion. In this case implementation of artificial lifts is difficult. This difficulty could be overcome by the use of coiled tubing, sliding sleeve and an anchor.

This paper presents a review of the CT capabilities that can be used in dual hole completions. This paper intends to discusses the guidelines of applicability of Coiled Tubing and design considerations for using Coiled Tubing as a sucker rod and also as production string in dual zone along with the pros and cons of coiled tubing. We have concluded our paper with some relevant recommendation on some operational and design strategies as well as future direction for integration of additional variable
New Technique to Identify Multiple Contaminated Primaries in Full-Stack Seismic Data and Possible Mitigation Measures: Gotnia Basin (Northwest Kuwait)
Authors: Heyam Ammar , Banik Nikhil , Adwani Talal Fahad , Ahmed Manowar , Srigiriraju Ramachandra
Published: December 2013

We present a case study with regard to multiple contamination of seismic data in post-stack 3D seismic data in the North Kuwait Gotnia subbasin, which holds very good hydrocarbon potential within Pre-Cretaceous reservoirs but faces considerable challenge in reservoir characterization because of its multiple contamination. This study attempted to focus mainly on the Pre-Cretaceous carbonate reservoir around the KM structure.

The main challenge is to deal with interference of 5th or 6th order peg-leg multiples with primary signals at the reservoir level. Peg-leg multiples are instances of short-path, multiple reflected seismic energy that can directly impact the seismic inversion results, facies mapping, structural interpretation, and hence depth prediction.

The improved approach to multiple attenuation could be demonstrated by a pilot processing using the following techniques on select locations. The new technique delineates a spatial an area which may be contaminated with multiples in post-stack 3D seismic data. First step tool for interpreter.Key elements gained from this method to implement multiple mitigation measures, which can reduce the multiple-contamination effect in post-stack data are: ∘Identifying spatial area of contamination by observation by horizon flattening.∘Nature of amplitude contamination over structurally favourable locations.The interference may indicate the nature of multiple contamination. This method is subject to testing.

A new approach to identifying and interpreting multiple contaminated primaries in full-stack seismic data provided a better interpretation of data for the North Kuwait Gotnia sub-basin. It revealed need for more multiple modeling and vertical seismic profiling (VSP) in all wells. However, it also provides a methodology for reprocessing for all available 3D seismic data through multiple mitigation that can improve seismic inversion, reinterpretation, geomodeling on newly processed 3D seismic data
Enhanced Oil Recovery by Nanoparticles Injection: Modeling and Simulation
Authors: El-Amin Mohamed F. , Sun Shuyu , Salama Amgad
Published: December 2013

In the present paper, a mathematical model and numerical simulation to describe the nanoparticles-water suspension imbibes into a water-oil two-phase flow in a porous medium is introduced. We extend the model to include the negative capillary pressure and mixed relative permeabilities correlations to fit with the mixed-wet system. Also, buoyancy and capillary forces as well as Brownian diffusion are considered. Throughout this investigation, we monitor the changing of the fluids and solid properties due to addition of the nanoparticles and check for possible enhancement of the oil recovery process using numerical experiments.
Marcellus Shale Gas Asset Optimization Driven by Technology Integration
Authors: Kaufman Peter , Atwood Keith , Forrest Gary , Walker Kirby , Wutherich Kevin , Delozier Denise , Perakis Alex , Borchardt Shannon , Hauser Ken
Published: December 2013

Integrating logging-while-drilling (LWD) measurements with pilot well log data and 3D seismic data provides a more accurate predictive mapping of unconventional reservoir properties than evaluations from the individual measurements alone. In this project, the final probability of drilling in a zone of good reservoir quality, as defined by the seismic attributes, had the highest correlation with production of any spatially mappable variable and provided the operator with a ranking of potential drilling locations. This link between production drivers and causal mechanisms allows optimal decision making, partly by distinguishing reservoir quality variation, which cannot be controlled, from operational behavior, which can be modified; untangling these two can mean optimal use of capital resources to exploit these challenging reservoirs.
Understanding Reservoir Properties Through High-Definition Microresistivity Images in Horizontal Shale Oil Wells Drilled with OBM in China
Authors: Yun Xie , Huijun Hou , Hui Guan , Laronga Robert J. , Zhongbin Xin
Published: December 2013

Oil-base mud (OBM) is an increasingly popular drilling fluid used to protect the wellbore stability in horizontal wells drilled in China targeting shale gas or oil. In these reservoirs, an in-depth understanding of fracture attributes is critical for stimulation design and well placement optimization, but the resolution and coverage of traditional imaging technology for OBM limits the extent to which this objective may be achieved. A microresistivity imager achieving resolution and coverage similar to established technology for conductive water-base mud (WBM), fully capable to distinguish fractures and formation structural features in OBM, has been a much needed technology development to provide critical insight required for shale oil exploration.

The paper presents a case study from the Bohai Bay basin in Eastern China, where oil shale formed in the faulted depression lacustrine sub-basins of the Lower Oligocene. One horizontal exploration shale oil well was drilled with OBM for reservoir evaluation. Only a gamma ray log and new, high-definition microresistivity image logs were acquired due to difficult operating conditions, which made it a great challenge to interpret reservoir properties and optimize stimulation design. Fortunately, two nearby vertical wells were drilled and evaluated in detail prior to design of the horizontal well, making use of geochemical, advanced acoustic, and microresistivity image logs to optimize placement of the lateral, thus providing a reference for estimation of the reservoir properties.

The results showed that the new, high-definition resistivity imaging tool gives detailed images suitable for full fracture and structure characterization, and that such high-quality images are feasible even in wells drilled with OBM. Interpretation of high-definition microresistivity images to build a near-well structural model provided a framework for correlation of fracture, reservoir, and mechanical properties from the vertical wells to the horizontal well. This provided a clear picture as to how the lateral well trajectory progressed stratigraphically within the shale section, as well as the distribution of the fractures, reservoir and non-reservoir rocks, total organic carbon (TOC) and minimum geo-stress along the well trajectory. Subsequently, this rich model provided the needed critical inputs to decide how and where to complete the well with an optimized stimulation design.
Innovative Methodology to Riglessly Restore the Functionality of the Sub-Surface safety valves Sc-SSSV with Damaged Control Line
Authors: Fahim Mohamed , Elnaggar Hossam , ElBarbary Abd Allah , Arab Mohammed Abu , Keshka Ashraf , Daghmouni Hamdi Bouali , Al Karra Mohamed , Soufan Ammar , Joseph O’Connor , Elasmar Magdi
Published: December 2013

The company introduced a new era of Well Integrity Management system as a continuous assessment and verification process to ensure the integrity of the wells is designed, monitored and maintained throughout the well life cycle.

Failure of any well barriers is not allowed. If a barrier fail, an immediate action should be taken to restore the well integrity, which is one of the important business elements in oil and gas fields; and hence according to well integrity standards utilizing well control devices are mandatory to protect human life, and reduce the potential for environmental pollution in addition to minimize the loss of production.

The surface control subsurface safety valve (SC-SSSV) is an integral part of the overall safety system of any well and it is the only method that provides sub-surface isolation in case of emergency due to uncontrolled surface or sub-surface event. Therefore it is mandatory to have functional SC-SSSV installed in the production tubing in all gas and oil wells, irrespective of their location, to stop the flow in case of a catastrophic failure.

The SC-SSSV is adjusted to be held in the open position by hydraulic positive pressure from surface. This pressure is applied through a control line in the tubing-casing annulus running from the valve to the surface. In case of an emergency shutdown the hydraulic pressure will be released forcing the safety valve to close. However the control lines could leak, plug or break leading to losing the functionality of the safety valves. The only way to rectify SC-SSSV C/L problems is by a rig work-over to replace with new C/L.

This paper describes the innovative methodology, which is the first application in the UAE & Middle East, to install Baker Hughes system "Inject-safe" controlled sub-surface safety valve which has a similar operating philosophy to the conventional SC-SSSV. The "Inject-safe" C/L deployment is on the inside of the tubing which drastically reduces the cost. This unique approach has been successfully executed in one of the super giant onshore fields in Abu Dhabi through an extensive techno-economical study.

The paper goes through the methodology of candidates’ selection, the system requirements and modification in wellhead and the trial results through specific testing criteria in one of the wells as part of a field pilot. The risk assessment is also discussed along with the execution process.

The cost impact of installing the new system as proved in the pilot through a techno-economical evaluation well will be highlighted, in addition to well performance pre/post installation combined with the project conclusion and recommendation for future implementation.
A New Artificial Lifting of High Productivity Wells: A Production Optimization Scheme
Authors: Qahtani Abdullah Al
Published: December 2013

The need for oilfield operators to verify that wells are being produced at their optimum capacity and in a cost effective manner is always a priority. The need for total well management to reduce operating costs, increase oil production and increase net income from wells requires an integrated analysis of the pumping system including the performance and interaction of all the elements: the reservoir, wellbore completion, and the downhole pump. Well Completion is typically designed to assure certain oil flow rate whilst producing manageable volume of water to ensure good reservoir sweep efficiency and management. Completion design is always based on collected production data of forecasted reservoir performance of changing pressure and water cuts.

As oil fields mature with subsequent increase of water cut and decrease in pressure, artificial lifting is becoming a vital mechanism for maintaining the production plateau of the field. With the emergence of the inflow control devices (both passive and active), the thrust for artificial lifting is delayed due to the delay of onset of water production or reduction of water volume produced. Very recently, the industry has looked into combining artificial lifting with controllable inflow devices.

This paper addresses the different optimization scenarios of well completion in high productivity wells considering the life cycle of artificial lift systems (mainly ESP’s) and different flow control mechanism. The paper highlights cases of applications extreme values of water gravities. In addition, underlines the economic viability of artificial lifting due to maintaining production and reducing cost in some applications.
Multi-attribute Seismic Analysis using Fractal Dimension and 2D & 3D Continuous Wavelet Transform
Authors: Saraswat Puneet , Raj Vijay , Sen Mrinal K. , Narayanan Arun
Published: December 2013

3D post-stack seismic attributes provide an intuitive and effective way of utilizing seismic volumes for reservoir characterization and development, and further identification of exploration targets. Some of the seismic attributes can aid in precise prediction of geometry and heterogeneity of subsurface geological settings. These can also provide useful information on petro-physical and lithological properties when combined with well-log information. There exist numerous seismic attributes providing unique interpretation on some aspects of subsurface geology. Of these, proper demarcation of structural features, such as location and edges of faults, salt domes, their throw and extent, has always been of primary concern. In this paper we propose new multi-attribute seismic algorithms using fractal dimension and 2D/3D continuous wavelet transform (CWT). The use of higher dimensional wavelets incorporates information from ensemble of traces and can correlate information between neighboring traces in seismic data. The spectral decomposition based on CWT aids in resolving various features of geological interest at a particular scale or frequency, which when rendered with fractal attribute demarcates the boundaries between those. We apply these two algorithms separately to a seismic amplitude volume and co-render output volumes together with some weights to yield a final attribute volume incorporating information from above mentioned algorithms. We demonstrate the efficacy of these two algorithms in terms of resolution and proper demarcation of various geological structures on a real seismic data. Results illustrate better illumination and proper demarcation of various geological features such as salt domes, channels, faults etc. at a desired frequency and how simple mathematics can provide tools to extract most of the information from seismic data.
Leveraging Multiple Digital Assets to Impact Overall Production Business: A Model Framework for Achieving Strategic Business Intelligence
Authors: Ashley S. , G.Bonilla J. C. , Eldred M. , Wood L.
Published: December 2013

Digital Oilfield (DOF) solutions generally consist of leveraging real-time asset awareness, in combination with intelligent analytical tools and collaborative business processes to continuously optimize production. Data is gathered and manipulated to create information, which in turn develops into knowledge for decision support. Knowledge is the critical piece and having the ability to exploit it to the benefit of the organisation should be fundamental. This is the essence of Business Intelligence (BI) and the core of the DOF value proposition.

The value of BI however is difficult to quantify. Some reasons include that it is often lumped together with other intangibles in valuation approaches, or the fact there is often an inability to distinguish between the effects of different knowledge assets. Irrespective of the reason, the challenge remains - and most often it is addressed at the organizational level where the DOF implementation occurs - namely, a given field or asset. Examining that level, it is easier to correlate DOF with an increase in production, increase in efficiency, or knowledge capture for a particular asset team. However, as one company implements evermore DOF solutions across multiple assets - incurring increasing costs along the way - questions arise concerning the overall value of the total investment from a corporate perspective. Typical questions include: What is the impact of all the DOF implementations on the overall production business? What is the value proposition to the company as a whole? How is the aggregate value measured? Is DOF something that should be implemented and standardized across the organization as part of the corporate strategic vision? What are the implications to the organizational structure with regard to shifting from a functional to a collaborative decision making paradigm?

This paper presents a recommended structure and development methodology for creating a DOF initiative framework that integrates multiple implementations to realize value that goes beyond asset level production optimization: taking it to a whole new level by achieving not only tactical, but strategic business intelligence.
Effect of Metal Ions on the Rheology and Thermal Properties of Polymeric Lost Circulation Material
Authors: Omer Mohammed , Sultan Abdullah
Published: December 2013

Drilling oil wells is burdened with a large number of technical and economical problems that makes it unprofitable or difficult to further develop some of the fields. One of the most commonly occurring problems during drilling an oil well is Lost Circulation. Lost circulation is the continuous loss of drilling fluid when it encounters fractures, high permeable zones or pore spaces, during drilling. Lost circulation can lead to blowout endangering the life, and causing serious damages to the drilling rig. Polymeric materials such as Polyacrylamide can be used as Lost Circulation Materials (LCMs) to seal the fractures and prevent the drilling fluid from entering into them.

Metal ions such as Magnesium, Manganese and Calcium can be injected with the drilling fluid to increase the viscosity or to increase flexiblity of polymer and form a gel that seals the loss zone. This paper will demonstrate the influence of these counterions on viscosity, thermal stability, and elastic modulus of the Polyacrylamide (PAM) polymer which is used as a main component in LCM. It has been observed that the concentration of counterions has noticeable effect on the rheological properties of PAM solution. On comparison of the results of viscosity between pure 1% wt concentration of PAM and that for a mixture consisting of PAM with 0.95 wt% and counterions with 0.05 wt%, there was a huge viscosity loss. For solutions with Counterions Ca, Mg and Mn2+ at 0.05 wt% concentration the viscosity decreased by 42.02%, 39.28%, 31.06% and 10.79%, respectively as compared with viscosity of pure 1 wt% PAM. This paper explained the chemistry behind such precipitation. Additionally this paper also presents the research findings of the effect of these counterions on the thermal stability of the PAM. The thermal stability of pure PAM considered was 70°C, but in the presence of the Ca, Mn and Mg ions, the thermal stability reduced.
Wellbore Asphaltene Cleanout Using a New Solvent Formulation in a Horizontal Open Hole Oil Producer in Carbonate Reservoir of North Ghawar Field–Scripting a Success Story
Authors: Murtaza S. , Al-Ruwaily A. A. , Taqi A. A. , Qahtani S. S. , Chacon Alejandro , Gonzalez Alexys Jose , Bustamante Ernesto
Published: December 2013

An organic deposit cleanout job was successfully performed on a horizontal openhole Arab-D reservoir oil well and a high oil rate was restored from the dead well. The well was treated with a proprietary chemical solvent using bullheading and coiled tubing (CT) jetting technique to have maximum coverage of the wellbore from the tubing to long open hole horizontal sections. The treatment performed for this job representedthe first application of this chemical in a carbonate field of North Ghawar.

A few wells in this area, lying within the boundary of a gas cap, have experienced asphaltene/paraffin problems that resulted in productivity decline and wellbore inaccessibility. A high gas-oil ratio (GOR) has been thought to be the main reason for asphaltene/paraffin precipitation inside the wellbore and near the formation. Organic depositswere observed to have accumulated in the wellhead and shallow tubing depth.

This well was drilled in 2007 on the periphery of the south gas cap of the field and died after being on production for three years at a relative low watercut. The well was reported with a high GOR and water cut around 2% to 3% before dying. Analysis of a downhole sample confirmed 100% hydrocarbon with 81% asphaltic presence. The asphaltene/paraffin deposition was identified as the main reason for the death of this well.

Chemical/solvent treatment using a CT jetting/pulsating mechanism was employed to have a maximum benefit. The solvent was proven in the lab to be very effective in dissolving asphaltene/paraffin and had a higher flash point. The job was performed in two stages. In the first stage, about one tubing volume of the solvent was bullheaded and left for soaking for 24 hours. In the second stage, the solvent was placed using 2" CT in the open hole section.

This paper describes in detail the nature of the asphaltene problem in this area, the formation mechanism, treatment selection, design and execution, and future prevention approach to avoid recurrence.
New Numerical and Analytical Models to Quantify the Near-Wellbore Damage due to Sulfur Deposition in Sour Gas Reservoirs
Authors: Mahmoud M. A.
Published: December 2013

The deposition of elemental sulfur as a solid phase will result in plugging the pore space available for gas flow and reduce the reservoir productivity. Elemental sulfur also can be deposited as a liquid phase if the reservoir temperature was greater than 115°C. The liquid sulfur will not flow at the same velocity as gas and in turn the gas flow will be restricted by the settled sulfur due to the huge difference between the liquid sulfur density and gas (Could be 20 times or more in certain cases). For the isothermal conditions in the reservoir, the reduction in reservoir pressure below a critical value will cause the elemental sulfur to deposit in the formation, and in turn the gas well productivity will be affected. Accurate prediction of sulfur deposition in the reservoir will help in better manage sour gas reservoirs with potential sulfur deposition problems.

In this paper new analytical and numerical models were developed to predict the effect of sulfur deposition on the damage of the near-wellbore. The damage will be quantified through the investigation of the effect of sulfur deposition on the skin damage value, relative permeability of the gas phase, and the change in rock wettability due to sulfur deposition especially in the near-wellbore region. The main objective of these models is to investigate the effect of radial distance on formation damage. Different rock and fluid properties accurate correlation were used in this model for better results prediction. Previous studies did not consider the change in gas properties with pressure, and numerically modeled the sulfur deposition as a condensate in a gas condensate reservoir. In this paper will consider r the sulfur adsorption and the actual physical properties of the sulfur will be used in the developed model. The optimum gas flow velocity will be determined based on the sulfur solubility.

Analytical and numerical solutions show that the deposition of sulfur was affected by the radial distance from the wellbore and sulfur solubility change as a function of the pressure drop. The numerical and analytical models showed good match in modeling the sulfur deposition in the near-wellbore area. Sulfur deposition was found to have a great effect on the rock wettability, and in turn the gas production will be affected. The model can be used to predict the critical flow velocity that the gas can flow without precipitating sulfur. The optimum gas flow velocity was estimated to be a range that maximizes the sulfur solubility in the gas.
Modern Practices in Estimation of Explored Petroleum Resources in Sedimentary Basins Including CBM Fields
Authors: Dani K. C. , Baskaran V. K. , Varyani S. , Kumar K. , Takru Loveraj
Published: December 2013

The estimation of resource includes all possible accumulation of oil & gas on the basis of the size, value of the reserves and the quality of oil & gas. The two interrelated studies are qualitative and quantitative estimation. The qualitative estimation reflects the geological model of the area and identified spatial variation of geological factors, favourable for generation and accumulation of hydrocarbons.

The quantitative prognosis is an expression of theoretical knowledge and observed pattern with the help of parameters which can be measured, collected and systematized. The distribution of hydrocarbon resources in the sedimentary basins is a fundamental requirement to plan the rationale of exploration and conversion of the resources into in-place hydrocarbon in future. However they provide an order of magnitude of estimate of potential, which is accurate enough to allow resource planning, and rational investment decisions.

The estimation of prognostic resources is based on the results of generalization of geological, geophysical, geochemical and hydro-geological investigations as well as on analogy of studied fields within the limits of the area under estimation with help of methods like William W. Mallory (1975) method and R.W. Jones (1975) factor model. Reserve estimation techniques include volumetric, material balance, decline curve analysis, simulation studies and geophysical techniques.

Inputs for CBM initially in place (CIIP) estimation include geological parameters, coal bed methane (CBM) specific parameters and the production history. CIIP will be classified as Proved and Unproved categories. The Unproved portion will further be classified as Probable and Possible categories. Reserve and Resource estimates are inherently uncertain. The classification system and the reporting standards differ widely. There is no universally accepted global standard. But SPE, WPC and AAPG definitions are most widely in use. UNFC a flexible framework that is possibly consistent with SPE, WPC and AAPG.
Implementing Seismic Colored Inversion to Enhance Reservoir Property Estimation in Frontier Exploration Areas: A Case Study in Central Saudi Arabia, Unayzah Reservoir
Authors: Nour Abdoulshakour , Al-Awfi Sami
Published: December 2013

Seismic Inversion methods have been in use in the industry for over 46 years. The earliest form of seismic inversion simply transformed seismic data to P-impedance, which is the product of density and P-wave velocity. The result was then used to predict reservoir properties such as lithology and porosity to better characterize reservoirs. This, however, proofed to be difficult as the P-impedance velocity also responds to the inseparable effect of reservoir fluids, lithology and porosity. The introduction of S-Impedance, which is less susceptible to the effects of fluid and lithology, made the results less ambiguous. Modern inversion uses algorithms that account for wavelet amplitude and phase spectra, which improved its utility in various reservoirs.

There are several types of Inversion algorithms used in the industry. Sparse Spike inversion aims at explaining the seismic reflectivity with the minimum set of layers. It can generate both relative and absolute inversion. In this type of inversion the contribution of the logs (low impedance) and the seismic (high impedance) is clearly defined. Model-based inversion is another class of inversion technique. This class of algorithms tries to achieve resolution beyond the seismic band by using impedance logs in the model. It also utilizes interpretations like faults and horizons to produce better result, which means extra work is need. There is also stochastic inversion algorithms which produce high resolution, non-unique inversion cubes and thus may take more time. However, they enable statistical analyses of these solutions. Other forms of inversion include colored inversion and inversion by trace integration (Pendral, 2001).

The exploration of frontier areas characterized by complex geology and sparse well control requires fast, iterative, intuitive, and accurate methods to estimate reservoir properties. Traditional full-band seismic inversion is time consuming and typically requires the expertise of an inversion specialist. Also the quality of the inversion results islimited by the lack of well control, which is required to construct an accurate background (low frequency) impedance model. The seismic colored inversion method has proven to be a novel method that provides both speed and accuracy in delineating reservoir properties across vast frontier areas with few well controls.