bluuebunny/crossref_metadata_2025 huggingface dataset:
Record Propped-Fracture Stimulation Performed from a Jackup Rig in the North Sea
Authors: Robertson Bruce , Ridley Elizabeth , Atchison Bryan
Published: February 2010

Proppant-based hydraulic-fracture stimulation in the southern North Sea is becoming increasingly popular and, in some marginal fields, can be considered crucial to maximize reservoir contact; thus, improving deliverability from tight-gas sandstone formations. Because of the low availability of purpose-built or temporary stimulation-class vessels in the North Sea, an alternative concept to place more than 250,000 lbm of proppant into well 49/17-14 from the Ensco-100 jackup rig was proposed, reviewed, and successfully executed.

This paper presents the prejob engineering process and executional summary of the North Sea’s largest rig-based proppant-fracture stimulation, where in excess of 250,000 lbm of resin-coated proppant was placed at fracturing rates of 35 bbl/min, with greater than 7,000 hydraulic horsepower available.

Discussed within this paper are prejob planning measures and the logistical challenges overcome during completion of the project. In addition, the paper introduces the first use of a microemulsion surfactant in the North Sea to help optimize cleanup time by reducing in-situ capillary pressure.

The overall success of this project proves there is a viable commercial and technical alternative to vessel-based fracture stimulation in the North-Sea market where suitably sized rigs are available.
Precise Method Using Resistivity Imaging Tool for Estimation of High Resolution Reservoir Parameters Calibrated to Reservoir Description Tool and Nuclear Magnetic Resonance Data for Better Reservoir Characterization
Authors: Reda Ahmed , Hakim Hashem Abdel
Published: February 2010

This paper explores a successful method for predicting high-resolution saturation, permeability, and porosity from resistivity imaging acquired with wireline logging. By integrating the best attributes of resistivity imaging and both wireline NMR and pressure testing information, this method is shown to produce better reservoir evaluation and production enhancement when applied to a homogenous sandstone reservoir that is relatively free from micro-bound porosity and layering.

Three available wireline formation evaluation technologies used in concert with conventional macro-wireline logs can substantially improve reservoir evaluation in terms of porosity, permeability and saturation. These technologies include the following: Nuclear magnetic resonance (NMR), includes tools such as the MRIL®-Prime tool, which provides accurate estimates of formation porosity, permeability, saturation, and hydrocarbon properties, albeit with relatively coarse vertical resolution compared to resistivity images, which can be enhanced by post-processing techniques.Resistivity imaging, such as the X-tended Range Micro Imager (XRMI™) tool with vertical resolution down to 0.10 in. These tools provide high-resolution porosity, permeability, and saturation prediction in clastic reservoirs based on estimates of micro-bound and producible porosity by means of integration with NMR and conventional logs.Pressure and sampling tools, such as the Reservoir Description Tool (RDT™) formation tester, which provides reservoir pressure, anisotropy, lateral and vertical connectivity, producibility, and fluid mobility measurements, which can be converted to permeability using fluid viscosity from fluid sampling.

The new method uses a special post-processing technique for enhancing the vertical resolution of the NMR data. By providing reliable and accurate predictions of saturation, permeability, and permeability, the method integrates NMR-bounded porosity, conventional resistivity, and the NMR saturation resulting from the magnetic resonance imaging analysis (MRIAN™) post-processing model.
Waterflooding Performance in Inclined Communicating Stratified Reservoirs
Authors: El-Khatib Noaman A.
Published: February 2010

A mathematical model is developed for performance prediction of waterflooding performance in communicating stratified reservoirs with a dip angle from the horizontal. The effect of the gravitational force is reflected by a dimensionless gravity number in the fractional flow formula that accounts forthe dip angle and density difference between the displacing and displaced fluids. The developed modelis used to estimate the fractional oil recovery, the water cut, the dimensionless time and the injectivity ratio at times of water breakthrough in the successive layers. Eqations are also derived for the case of continuous log–normal permeability distributions characterized by the Dykstra–Parsons variation coefficient VDP or the standard deviation of thelog–normal distribution σk.

Solutions for inclined communicating stratifiedsystems with log normal permeability distribution were obtained and the performance was compared withthat of the horizontal systems. The effects of the gravity number, the mobility ratio and the Dykstra-Parsons permeability variation coefficient, VDP, on the performance are investigated and discussed.

The obtained results showed that the gravity effect of the dip angle enhances the performance in terms of delayed water breakthrough, higher fractional oil recovery and lower water cut. This improvedperformance is more significant in the case of unfavorable mobility ratio. Reservoir dipping does not affect the pseudo relative permeability functions but results in a decrease in the injectivity ratio
Optimization of Water Injection Facilities in Mature Field
Authors: AlKhalifa Mohammed H , AlKhalifa Hani H
Published: February 2010

This paper will discuss in details the balance between disposal system flexibility and system efficiency. Typically such systems are designed with some uncertainties from reservoir performance and production rates. This fact encourages designers and operators to oversize the system to be in the safe side. However, this approached comes on the expense of efficiency.

This paper describe an efficient approach to evaluate the existing water handling system within upstream facilities in terms of capacity and operation cost and to define the required upgrades and areas of optimization. This approach applies to upstream Gas Oil Separation Plants where produced water is gravity separated, treated and re-injected back into the producing formation. Water is therefore accounted for in the injection over all mass balance calculations.

The paper will show a new approach to effectively analyze produced water disposal systems and evaluate alternatives to significantly improve their efficiencies. This approach evaluates the whole system from the suction of the disposal pumps to the bottom of the disposal wells of multiple facilities simultaneously. Addressing the reservoir pressure, headers and laterals, pumps configuration and drive mechanism in details to be able to accurately balance required flexibility and improve efficiency. This approach addresses both short and long term optimization needs.
Prediction of Porosity and Permeability of Oil and Gas Reservoirs Using Hybrid Computational Intelligence Models
Authors: Anifowose Fatai , Abdulraheem Abdulazeez
Published: February 2010

This work utilizes the capabilities of Data Mining and Computational Intelligence in the prediction of two important petroleum reservoir characteristics, viz., porosity and permeability, based on the hybridization of three existing Artificial Intelligence techniques: Fuzzy Logic, Support Vector Machines, and Functional Networks, using several real-life well-log data.

Two hybrid models have been built. In both, Functional Networks was used to select the best input variables for training directly from data using its functional approximation capability. In the first model, the selected input variables were passed to Type-2 Fuzzy Logic System to handle uncertainties, if any exists. These are then passed to Support Vector Machines for training and making final predictions using the test data. In the second model, the input variables selected by Functional Networks were passed to Support Vector Machines to transform them to a higher dimension, called a feature space, and then to Type-2 Fuzzy Logic to handle uncertainties, if any exists, extract inference rules and make final predictions using the test data. The results showed that the hybrid models perform better with higher correlation coefficients than the individual techniques when used alone for the same sets of data. This is a further confirmation of the theory that hybrids perform better than their individual components and possess the best qualities of each of the components. In terms of execution time, the hybrid models took less time for both training and testing than the Type-2 Fuzzy Logic, but more time than Functional Networks and Support Vector Machines. This could be the price for having a better and more robust model.

The process of combining multiple computational intelligence techniques to build a single hybrid model has become increasingly popular. As reported in the literature, the performance indices of these hybrid models have proved to be better than their individual components when used alone.

Hybrid models are extremely useful in the field of reservoir characterization in petroleum engineering which requires a high quality information and accurate prediction for efficient exploration and management of oil and gas resources.
Natural Gas Economic Challenges in North African Countries
Authors: Ellafi J. S
Published: February 2010

The strategic location of North African natural gas producers play an important role in attracting natural gas investors which the industry is very much in need of; to accelerate the development and procurement of gas projects both in the upstream and down stream sector.

North African countries need to tackle many challenges in order to make use of both local and foreign private investors that are anxious to participate in development of natural gas projects especially after recent increase in natural gas demand which concedes with energy price improvements, recent economic growth of many countries in the region played a major part in attracting local and foreign private fund to develop natural gas resources, risk management procedures to tackle these challenges are necessary for economic success of gas projects in the region. This paper outlines the difficulties and challenges that retard the development of natural gas industry in the North African region.
Enhanced Field Surveillance through Real-Time Data Visualization in Dubai Offshore Fields
Authors: Shnaib Fathi , Nadar Manickam S. , Chacon-Fonseca Joel
Published: February 2010

Dubai Petroleum (DP) currently has offline production optimization processes in place for optimizing Dubai’s offshore gas lifted assets, both at the well and system levels. In order to achieve real-time well surveillance and optimization capability for the whole asset, DP has deployed a field-wide real-time well performance monitoring system for all the producers and injectors in the entire asset. This paper describes the various phases of the real-time well performance monitoring project; justification, pilot test, full field implementation and current applications of this tool. The technical and economic benefits of such systems and the lessons learned from this implementation will also be discussed.

The "Data to Desktop" well performance monitoring system aids the engineers to review well performance related trends in a continuous manner. The system has helped identify well performance-related issues in a very short period of time and aided in solving these problems with less production downtime than before. The tool has helped reduce the time spent by engineers for data gathering and issue identification. As the system is web-enabled and deployed through the company’s Intranet, it is possible to monitor the live well performance from any location.

The Real-time "Data to Desktop" system will allow DP to progress to the next step of real-time production optimization. The raw well data will be "cleansed" from spikes, noise and bad-data periods and utilized for calibration of the well models. The output of the models when compared with the field data can be used to automatically highlight the wells that are sub-optimal in their performance.

Faced with ever growing pressure to produce maturing fields optimally, asset operators are turning to digital technologies to help maximize the time spent by engineers in greater value-adding activities, leaving data gathering, "cleansing", processing and visualization to systems such as the well performance monitoring system that was implemented.
Accurate and Fast Method for Predicting Actual Top-of-Cement Depths in Eccentric Wellbores
Authors: PKS Sairam , Savery Mark , Morgan Ronnie
Published: February 2010

It is often perceived that a cementing operation is the last step in the drilling process, but any cementer can tell you that cementing is the first step to a successful completions process. Proper displacement of mud during cementing operations is not only critical for successful zonal isolation, but also for achieving asset-management objectives for increasingly difficult-to-reach hydrocarbon reservoirs. One of the challenges in these complex wells is to provide uniform cement coverage across the entire zone of interest, especially in targeted zones where casing or liner is decentralized (off-center). In these situations, an uneven pressure differential from decentralization causes uneven flow of cement. The result is a much different top-of-cement (TOC) on the narrow side of the annulus versus the wide side of the annulus. Real-world negative effects of this phenomenon can include annular pressure build-up, the necessity of remedial squeeze work, and even well abandonment.

A better understanding of fluid movement through the eccentric annuli can help predict the true TOC around decentralized casing. Therefore, a first-of-its-kind flow-predictor program was developed with the capability to accurately predict the TOC and corresponding fluid velocities for a three-component mud-spacer-cement system in eccentric annuli. It is based on a generalized mathematical model for pressure-drop prediction, developed using more than 1,700 experimental data points in physical models mimicking that of actual downhole geometries. Experimental data consisted of narrow and wide-side flow rates for 14 different fluids, within a density range of 8 to 21-lbm/gal, circulated in standard oilfield pipe and hole configurations ranging from 4.5-in. × 6.5-in to 9.625-in × 12.25-in. Standoffs varied between 12 and 82%. Yield point, viscosity, and shear thinning indices of these fluids varied between 0 and 50-lbf/100ft2, 1 and 157-cp, and 0.4 and 1, respectively. Various simulations are shared to reveal the properties and parameters required to help achieve uniform flow around the annulus and a balanced TOC.
Multi-Stage Hydraulically Fractured Shale Gas Rate Transient Analysis
Authors: Bello Rasheed O. , Wattenbarger Robert A.
Published: February 2010

The common completion technique in horizontal shale gas wells is by hydraulically fracturing in multi-stages. In this paper, a linear dual porosity model is used to approximate the shale gas completions with a horizontal well and multiple hydraulic fractures. Five flow regions are identified with this model. Region 1 is transient drainage in the fractures, Region 2 is simulataneous drainage from matrix and fractures or bilinear flow, Region 3 is the infinite-acting case, Region 4 is transient drainage from the matrix and Region 5 is the boundary-dominated flow case. Derived equations are presented for each of the flow regions.

It appears that field production data exhibit Region 4. This transient flow regime is the only flow regime available for analysis in many wells. A skin effect for Region 4 is observed in many wells and described in this paper. A procedure is presented in this paper to analyze field data and is illustrated with a sample case..
Risk Analysis and Decision Making in Relative Permeability Modifier Water Shut-Off Treatment
Authors: Awad Quosay , Ibrahim Abdelhalim , Salah Ramzi , Bakheet Ahmed
Published: February 2010

In the last few years, water shut off (WSO) treatments in production wells have started to become as a part of standard well service. Decision making, taking into account the uncertainties of reservoir and well data, is a difficult job with regard to WSO treatment especially with the current high oil price.

The success of any relative permeability modifier (RPM) treatment is depending on the pre-treatment reservoir and well production parameters. The uncertainty within these parameters leads to improper prediction of the post treatment condition and consequently a wrong WSO treatment decision may be taken.

An RPM WSO treatment evaluation model was developed based on Monte Carlo simulation and a developed radial flow equation. The model predicts the post-treatment water cut and production rates specifying a range that extends from minimum output value to a maximum value in order to alienate any chances of associated risks. The simulation inputs and results are also illustrated as probabilistic distributions providing a complement to the previously cited production results. Decision tree model is used to choose the best option among different RPM WSO treatment scenarios.
Case Histories: Real-Time Downhole Data Increase Drilling Efficiency
Authors: Sharma Nitin , Srinivasan Ananth , Hood James
Published: February 2010

With current trends in exploration, drilling operations are becoming more complicated and cost-intensive. Although the focus is often on reducing non-productive time (NPT) and invisible lost time (ILT) in these high-tech wells, little time is spent on benchmarking for the time taken during common drilling and non-drilling procedures.Today’s downhole MWD systems are able to transmit information in real time, such as weight on bit (WOB), torque on bit (TOB), downhole azimuthal bending moments, downhole RPM and drilling dynamics diagnostics. However, decisions in wells ranging from simple to complex are still made using traditional surface-acquired drilling data. This paper includes cases where the use of downhole drilling data increases drilling efficiency. Six case histories describe four different applications where a downhole optimization sub’s (DHOS) real-time data was used to improve drilling operations.
New Integrated Approach for Diagenesis Characterization and Simulation
Authors: Pontiggia M.. , Ortenzi A.. , Ruvo L..
Published: February 2010

The study of the diagenetic processes is a fundamental step to achieve a more accurate and reliable prediction of flow performance, as diagenesis alters the original relationships between depositional facies and petrophysical properties. Thence, a quantitative integration of all data and available analysis is a key-factor to obtain a realistic reservoir model.

A new integrated approach for diagenesis characterization and simulation is here presented. An application case was performed on the silici-clastic Egyptian reservoir of Baltim starting from quantitative diagenetic data.

Chlorite content, which is here strictly related to grain size, affects the overall reservoir permeability. Particularly, "pore filling" type chlorite is responsible for the flow performance deterioration.

A relationship between diagenesis and log data was defined using density and spectral gamma ray (thorium) logs as predictors of pore-filling chlorite. A good relationship was also observed between grain size and the previously defined log-facies from multivariate statistical processing (cluster analysis), enabling us to assign a well defined depositional meaning to each of them.

The right evaluation of the petrographic-diagenetic input represents an excellent "starting line" for the following phases.

First, a traditional reservoir workflow (pre-diagenesis characterization) has been carried out testing different geostatistical facies simulations approaches (Sequential Indicator Simulation, Object Based Approach, Truncated Gaussian Simulation, Pluri Gaussian Simulation and Multiple Point Statistics). Then, a new methodological workflow for post-diagenesis reconstruction has been implemented, using a matrix that combines sedimentological information and diagenetic indicator at wells. Finally the petrophysical parameters have been simulated classically according to the characteristics of each post-diagenesis facies.

The results, compared to well test permeability and analysed with the flow simulator, show a good to very good match with the measured data. The match quality is clearly dependent on the mutual consistency of the facies distribution and the conceptual sedimentological model conditioning diagenetic effects.
Enhance Digital Oil Fields by Plugging the Technological Capability Gap
Authors: Holdaway Keith R.
Published: February 2010

The oil and gas industry needs to plug the capability gap with pertinent technology that embraces the current trends to improving productivity. Digital oil fields have to engage the geosciences community and the business decision makers, surfacing knowledge from the plethora of accumulated data, both real-time and historical.

Solutions must integrate not only the data, but extant applications and physical monitoring systems, and enable efficient collaboration between these facets to perform tasks faster and with more effectiveness and efficiency. With improved workflows and computing potential, it is now possible to ascertain the risk assessment and quantification of uncertainty inherent in improving productivity. The cost implied by poor predictions has to be mitigated by improved integration of disciplines and data fusion by adopting soft computing methods such as neural networks, fuzzy logic and probabilistic reasoning instilled into efficient workflows and processes. Reservoir characterization is a crucial player in modern reservoir management, and can lead to improved and timely reservoir decisions and this leads to heightened value of the oil and gas assets.

This paper draws upon a case study that ameliorates the path to knowledge that is derived from available data. Let us look at a reservoir surveillance management solution that embraces a predictive detection and alerting solution to improve production forecasting and planning, and so assist in managing corporate risks and investments. Also, as we walk through a digital oil field workflow, we can focus on some of the soft computing techniques such as neural networks and fuzzy logic that lend credence in reservoir characterization.
Health Risk Management
Authors: Shehata Elsayed Saad
Published: February 2010

Occupational Health (OH) Management is the management process, through which corporate resources are organized and used to promote well-being and prevent, or minimize, the adverse health impact of work on personnel and contractors. Failure to control occupational health risks in the workplace can result in a wide range of effects, from general worker under performance to premature deaths. It is also recognized that good occupational health performance is not only ethically sound, but it also makesgood financial and business sense. It is also an essential component of the HSE Policy.

Health Risk Management is a modern fast moving subject as it covers all aspects of risk associatedwith the worker environment and its affect on health.Today's Occupational Health and Safety Professionals take the pro-active approach by trying to prevent ill – health and accident beforeit happen.

Petrobel developed and implemented a new Health management system with reference to Egyptian Legislation, Eni E&P (shareholders) standards and industry best practice.

This Occupational Health Management System includes: ▪Medical Assessment Programe▪Fitness to Work – Minimum Medical Standards▪Catering & WaterHygiene & Quality Standard▪Minimum Equipment Standards for Petrobel Medical Facilities
Propped Fracturing with a Novel Surface Cross-linked Acid in High Temperature Deep Carbonate Formation
Authors: Ding Yunhong , Li Yongping , Xu Yun , Cheng Xingsheng , Wang Yonghui , Zhang Fuxiang , Jianxin Peng
Published: February 2010

Acid fracturing, as a conventional and effective stimulation method, has been widely used in carbonate formation. But because of serious acid leak-off and rapid acid/rock reaction speed, the length of effective acid etched fracture is always restricted, even the high viscosity acid and emulsified acid were applied; besides, the effective duration of etched fracture was short, especially in deep well. The propped fracturing can supply longer fracture and long-term effective duration, but its ability of connecting natural fracture or fissure is poor because the fracturing fluid is unreactive with the formation. So the propped fracturing with a novel surface cross-linked acid (SXA) is proposed, because it can not only realize long fracture length/deep penetration, but also connect more natural fracture/fissure to maximize the permeable area as possible.

In order to realize the technique, a novel temperature-stability and shearing resistance delayed cross-linked acid (SXA) was developed to qualify for the fracturing treatment. Meanwhile the effect of HCl on one high strength ceramic proppant was also studied, and the results showed the crush resistance and conductivity of proppant is unaffected. So the SXA and the acid- resisting proppant provide the basis for acid propped fracturing, and a comprehensive fracturing technique was developed.

Acid propped fracturing with SXA was processed in the carbonate formation with depth > 5000m and temperature >140℃. A volume of 36.2m3 proppant was successfully pumped into the formation with the maximal proppant concentration exceeding 450kg/m3. The net pressure matching indicated that the propped fracturing created long conductive fracture and realized deep penetration. The new technique provided a new and broader option of carbonate stimulation.
Improving HSE Contractors performance
Authors: Shehata El Sayed
Published: February 2010

Today’s oil & Gas industry is showing an increasing tendency to have more dependency in outsourcing the most for achieving its goals. The most evident case can be appreciated in areas that are generally executed using specialized contractors and manpower.

Petrobel places a continuing emphasis on the management of health, safety and environmental protection implemented by the Contractors working in its sphere of operations in order to ensure that all reasonable protection is provided to preserve personnel, plant, equipment and the environment.

One of the key points is finding the right balance between the expected performance by the contractors and the amount of resources and time required to put in place by the contracting company to maintain a sustainable continuous improvement process to achieve an integrated good HSE performance by both parties.

Good HSE reputation is ringing the bells all over around the world and this means reliability and profit wins or losses. Today’s stock market is more sensible than ever and it is impossible to say that we are achieving well when our contractors are poorly performing.

Contractors HSE Management is established to ensure that a standard and uniform approach is adopted by Petrobel for the evaluation of Health, Safety and Environment Management Systems developed and implemented by Contracting Companies at various phases of business.

Contractor HSE Management System should help adopt a common strategy by Petrobel for dealing with different categories of contractors in the aspects of HSE Management from the pre-qualification stage up to the completion of contract.

Contractors should be urged to develop their own HSE Management Systems in proportion with the risks encountered during a contract period, so as to reduce the risks to as low as reasonably practicable level, taking into account the cost benefit to achieve this objective.
The Key Drivers Determination for Offshore Plants Decommissioning and Abandonment Cost Estimate
Authors: Michetti V.. , Nicotra G.. , Dresda F.. , Tignanelli A.. , Moore W..
Published: February 2010

In the last 10 years the Oil & Gas Industries have begun tackling the complex issues related to the end-of-life of Upstream Assets Decommissioning. Theses are especially relevant for offshore activities due to their environmental impact and the elevated costs.

The introduction of the SFAS 143 principle in the United States, which defines the criteria for Decommissioning and Abandonment costs of production assets allocation and establishment, for companies listed on the New York Stock Exchange, requires such companies to report Abandonment funds.

In Eni E&P a tool for decommissioning cost estimating (property of Eni E&P Division) was required in order to evaluate the abandonment fund quickly and with a good accuracy.

The work to be performed was: to inspect all the techniques for topside total removal, abandonment and removal of substructure and sealines, taking into account local and international legal constraints, then to evaluate cost–estimate key drivers. A unique cost breakdown structure has been defined for all methodologies in order to guarantee the congruity of the estimate: vessel, personnel and equipment are the three cost parameters used to evaluate the main cost elements such as Mobilization/Demobilization, Survey Pre/Post Removal, Flushing and Clean Up, Equipment and Personnel for Removal, Engineering & Management and Onshore Final Disposal.

Information about techniques, field of operation, advantages/disadvantages and unit costs have been gathered by analyzing Eni’s experiences, through a benchmarking of the most important international competitors, and through experts’ opinion.
Evaluation and Field Optimisation of Kinetic Hydrate Inhibitors for Application Within MEG Recovery Units, Gas Condensate Field, Mediterranean Sea
Authors: Allenson S. J. , Scott A..
Published: February 2010

The most common chemical treatment for hydrate formation is the use of thermodynamic hydrate inhibitors (THI), which act to shift hydrate equilibrium conditions toward higher pressures and lower temperatures. On systems where a THI is needed on a continuous basis, regeneration systems have been developed to lower the cost. The most common regeneration systems are methanol recovery and MEG recoveryunits (MRU).

While these recovery units can lower the cost of a THI treatment program, the large volume of THI needed for most operations remains a major problem for many operators. A new method to prevent hydrate formation that can significantly reduce the amount of THI needed is using a Kinetic Hydrate Inhibitor (KHI) in combination with a THI.

This paper will discuss the laboratory evaluation of KHI chemicals, deployment of KHI within a MEGstream and optimization of a combination of MEG/KHI when applied to an offshore gas/condensate field in the Mediterranean Sea.

The objective of the trial was to apply the selected KHI and reduce the MEG injection rate as far as the MEG injection system would allow. The operator imposed a 50% reduction in MEG rate as a target for a successful trial of the KHI chemical. During the trial it was possible to pass the initial target reduction of MEG and in fact a reduction in the MEG rate by 70% was recorded. During the trial unplanned shut downs (duration 3 days) occurred but even under these conditions the KHI was still effective.

The lessons learned during the selection and field optimization will be presented along with the economic impact that the reduction in MEG has made to this operation. The implications of these findings will be outlined in terms of impact on Capex projects such as the footprint/capacity of the handling/storage and recovery units. The impact that KHI application can have during the OPEX phase where it will also be shown such as de-bottleneck existing systems where salt loading and/or higher than expected produced water volumes are experienced.
Manufacturing Light Oil from Heavy Crude Ratqa Field, North Kuwait
Authors: Luzardo M. Luis C.
Published: February 2010

Heavy Oil from North Kuwait does not have an intrinsic commercial value by itself. The crude is estimated to have an API in the 11-18 API range and high sulfur of >5% wt., which makes extremely difficult the processing operation in a conventional crude oil refinery. Notwithstanding, currently there are two options to make this crude marketable: By diluting or Blending the Heavy Oil (11 API) with a much lighter crude oil to produce a blend to be placed in the open market, orBy processing the Heavy Oil in Upgrading complexes and, depending on the selected upgrading scheme, produce a range of upgraded crude oils which vary in API from 16 to 35 and have sulfur contentbetween 0.1 and 3.5 % wt.

The first option, blending the Heavy Oil with a much lighter crude oil, has the disadvantage of degrading a high value light crude oil (Between 80 and 140 mbopd of 46 API Light Crude) to produce a lower value blend (Between 140 and 800 mbopd of 16 to 30 API).

If the Heavy Oil (11 API as the worst case) is upgraded to 31 API and sold, and the Light Oil (49API), which would be degraded to make the blend is sold separately, the revenues would be very high.

kOC is studying all possible disposition options for the HO from North Kuwait. Only two options (Blending and Full Upgrading) are compared in this paper, but other options such as Refining the HO in Kuwait existing and/or new Refinery, using the HO as fuel to generate electricity, etc., will be considered and studied in detail before a final decision is made by KPC.

The technical challenge for studying this option (Upgrading an 11-15 API crude to 31 API) is to find the optimal upgrading technology and to integrate an optimal upgrading scheme capable of manufacturing an upgraded crude oil with a commercial market value, as one option to dispose the Heavy Oil. That upgrading scheme is presented, in this paper, as an option for disposition of the HO from North Kuwait.

The significance of the studied options for KOC as a National Oil Company would be the technical contribution, to the overall project economics, arising from the combination of upgrading technology with the optimum upgrading processing scheme capable of producing a viable commercial option.
Determination of the Aquifer Activity Level and the Recovery of Water Drive Gas Reservoirs
Authors: Li M.. , Yang W. J. , Xiao Q. Y. , Liu S. C. , Zhang J.. , Peng G. M.
Published: February 2010

The judgment of the aquifer activity level and the recovery of waterdrive gas reservoir are intricate and crucial. The paper is to develop a new criterion to determine the aquifer activity level and a new chart method demarcating the range of recovery variation. In the first place, reasoning and defining the new criterion of the determinate aquifer activity level is obtained by water influx coefficient B, based on the material balance equation of water drive gas reservoirs and the study of previous scholars. Thus a theoretical curve equation and a suppositional curve equation are derived and defined. The former one is pr(1-RgB)=1-Rg, which shows the relationship between the relative pressure pr and the degree of reserve recovery value Rg with different B. The latter one, pra=(1-ER)/(1-aEva)(where a=Sgr/Sgi), relates to the ratio of residual gas saturation and original gas saturation Sgr/Sgi, the ultimate volumetric sweep efficiency Eva and represents the relation between the relative abandonment pressure pra and the recovery ER. Finally, a set of charts is established by the two equations, by which we can set up a table to determine the variation range of the recovery with corresponding Sgr/Sgi value and Eva value when the aquifer is at different activity level.
Improved Lithology Determination from Nuclear Logs in Complex Carbonate Environments
Authors: MacDonald Robin , Bradford Charles , Kersey David G. , Zhang Tianhua , Alsuhaibani Assim , Crary Steve
Published: February 2010

A multiwell study integrating mineralogy from core samples’ X-ray diffraction (XRD), standard openhole logs, and capture spectroscopy logging measurements was undertaken to understand differences between the log and core seen predominantly in anhydrite intervals. Determination of accurate lithology is important in oil and gas reservoirs because mineralogy affects the accurate determination of porosity, producibility, and reserve estimates.

The formation consists of calcite (limestone), dolomite, and anhydrite, which are common in many carbonate reservoirs around the world. Small amounts of pyrite, other sulfides, clay, and quartz are also found. Analysis of this complex mineralogy is further hampered by environmental complications that include high borehole and formation temperatures and heavy barite-weighted mud, which results in the photoelectric factor (PEF) not being a reliable measurement.

In this case study, a positive bias in the log-derived anhydrite volume was observed in tighter, nonproductive carbonate sections. As the anhydrite volume is determined directly from the capture spectroscopy sulphur measurement, this bias suggested a potential problem with the measurement. As the bias was small (0 to 3 weight percent) and the anhydrite distribution in the rock is very heterogeneous, the determination of the cause of this apparent problem was difficult.

A number of different potential causes of the bias were reviewed to determine if they adversely affected log-derived lithology. Capture spectroscopy data acquired at faster logging speeds demonstrated the bias at small volumes of anhydrite; the bias disappeared in zones with significant amounts of anhydrite. In addition, mineralogy and elemental analysis from veneer slabs improved the quantification of the sulphur and consequently, the anhydrite content of the formation, enabling accurate determination of anhydrite volumes, even in the heterogeneous sections. Proper averaging techniques of the core data with log data also verified the sulphur bias at low anhydrite levels. The results of this study confirmed that the apparent sulphur bias was the result of statistical precision. Improvements to the log data require slower logging speeds, modifications to data acquisition, processing, and better wellsite log quality control.
Barge Mounted Coil Tubing - An Operational Safety Case Study in South China Sea
Authors: Hairi M Hairi , Yusoff Afendy , Wibisono Rahmat
Published: February 2010

Petronas Carigali Sdn Bhd (PCSB) is one of major oil and gas companies in South East Asia. It has had years of experience operating coil tubing unit (CTU) on relatively large oil and gas field platforms. Vast of field experience and project lessons learned have been captured, refined and eventually embedded in the company’s CTU standard operating procedures. These have lead to zero lost-time incidents (LTIs) cases in 5 years of CTU operations particularly offshore Terengganu in South China Sea. The CTU operations are often complex and involve heavy lifting, weighty machineries, minimal deck space and long working hours. Hence, to achieve such a record through out the 12 months in a year with 2 units running concurrently is definitely something to be noted.

In February 2009, PCSB embarked on it first barge mounted CTU operation at offshore Terengganu. The option was choosen to access marginal field with small platform deck space and limited crane capacities. These include the process of lifting heavy equipment from workbarge with 60 degree angle to a 50 ft high platform during high swell, having to mobilize crews back and fourth from workbarge to platform and rigging up in dynamic condition. Furthermore, it was the first time the work barge crews experienced such operation and communication constraints due to remote and weather conditions further complicated the situation.

Knowing that field experience is almost zero for mounted barge CTU operations in PCSB fields, resources and time has been put to ensure that the HSE track record is intact. Starting with Project Risk Assessment (PRA) which involved all contractors and field operator personnel, the team then analyzed of the whole campaign chain. This paper will review PCSB project success experiences and lesson learns on how to do CT operation from Barge within small platform during moonson season with high level of safety.
Water Management and Production Enhancement: Case Studies of Greater Munga Field, Sudan
Authors: Bahuguna Ajay , Elbadri Mohd , Vazquez Alvarez Maria Leticia , Shaheen Tarek , Ahmed R.
Published: February 2010

Munga field of the Greater Nile Petroleum Operating Company (GNPOC) in Sudan has several wells that have commingle production from the Aradeiba, Bentiu-1 and Bentiu-2 formations. These formations are highly variable in terms of the reservoir properties, oil types and pressure regimes. Because of the contrast properties of different layers, the water cut phenomenon is relatively fast and severe which hampers the productivity and ultimate recovery of the individual well as well as the field.

For effective Reservoir Management and to limit the declining trend of the field, Water Management Techniques are applied in some of the wells of this field. Information obtained in the process was used for reservoir model calibration, well productivity prediction, low productivity diagnosis, and generation of new drainage points and remedial action for water management.

This paper discusses the technical details of three cases corresponding to the wells Munga-XX and Umm Sagura South-XX (USS-XX) and Munga-XY in which, a multidisciplinary approach has been implemented in order to determine depletion profile, produced oil and remaining reserves, locate any "by-passed" oil zones, determine oil and water contributions from each zone and shut off the excess water production while maintaining or increasing oil production.

The source of water entry was identified in multi-rate production logging using Production Services Platform and electrical probes through Y tool-ESP completion. Vx meter was carried out at surface to real time monitoring the well production during the production logging survey. The well depletion profile was determined using Cased Hole Formation Resistivity (CHFR*) tool. A multidisciplinary team processed and interpreted the logging data and based on the results remedial jobs were carried out

The general outcome of the remedial jobs based on this approach was a considerable reduction in water production in both Munga-XX and USS-XX wells as well as oil production gain, making this a successful job.
Lessons Learned from Drilling Horizontal Wells on Didon Field; Offshore Tunisia
Authors: Jardine P.. , Chaaouri M , Guyard A , Di Pasquale M..
Published: February 2010

The Didon field is located offshore Tunisia in the Pelagian Basin. It was discovered in 1976, and first production began in 1998. Following a decline in production from initial development wells, the latest phase of development drilling began upon commissioning of the production platform in 2006. Horizontal wells drilled in this latest development phase have resulted in production benefits. To date, six horizontal wells have been drilled on the field using various drilling techniques to optimize drilling efficiency and wellbore placement. Using wells drilled to date, this paper outlines the challenges involved in developing the Didon field. It describes lessons learned from application of the different drilling technologies together with the value of pre-well geological modelling and real-time geosteering techniques.
Developing and Helming Competent Engineers in Production Operations, Peninsular Malaysia Operations, PETRONAS Carigali Sdn Bhd
Authors: Hadi Sriyanta , Osman Azmee
Published: February 2010

Peninsular Malaysia Operations (PMO) is one of three domestic regions of PETRONAS Carigali Sendirian Berhad (PCSB) located in offshore of Peninsular Malaysia. The operations cover six of main operation areas namely PPD-D, PPD-F, PPD-L, PPD-P, PPD-S and PPD-T. Those operation areas have a wide operation ranges: from green to brown fields, from single to multiple products, from onshore terminal to offshore Floating Storage and Offloading (FSO) and Floating Production Storage and Offloading (FPSO), from heavy crude to light crude and from big to small fields. PPD-D area is gas producer; PPD-F, PPD-L, PPD-P and PPD-S areas are crude and gas producers while PPD-T area is onshore crude and gas terminals. PPD-F area is scatter small fields facilitated with one unit of FPSO and one unit of FSO; PPD-L area is a big oil field facilitated with water alternating gas (WAG) injection facilities, gas lift infrastructure and one unit of FSO; PPD-P area is scatter medium to small brown oil and gas fields facilitated with processing plant, water injection facilities, gas compression, gas lift infrastructures, crude pipeline and gas pipeline and PPD-S areas is a big oil and gas fields, facilitated with integrated gas and oil processing plant, water injection facilities, gas lift infrastructure, crude pipeline and gas pipeline. In some oil fields, water injection is applied for reservoir pressure maintenance while water flooding and Enhanced Oil Recovery (EOR) technologies are implemented to maximize oil recovery. Some fields are still producing naturally while in most brown fields, gas lift is suitable to assist the crude production. Production operations comprises of three functions: production planning, field production operations and production logistics. The main scope is crude and gas production and evacuation from the well up to the terminal or exporting point. As the think tank in production operations, production planning consists of three functions: production analyst, field and integrated production planning and hydrocarbon accounting and allocation. In day to day works, production planning is focusing on crude and gas production achievement. Field production operation as the heart of production operations, handles day to day offshore routine activities, process performance improvement, process plant upgrade and new production facility installation. Considering the importance and urgency of capability building, production operations has taken significant measures in developing and helming competent engineers in order to achieve and maintain excellent production operations as well as to sustain technical talent development. Analysis presented in this paper describes important keys in competency development; they are 1) capability mapping, 2) skill development process and 3) measurement and feedback.