bluuebunny/crossref_metadata_2025 huggingface dataset:
Challenging Rig-less Intervention Succeeds in Severance of Heavy-Walled Tubular
Authors: Qutob A. H , Forsyth G. R , Hassan I. K
Published: November 2012

The objective was to conduct a rig-less tubular cutting operation in an onshore well in Bu Hasa field, operated by Abu Dhabi Company for Onshore Oil Operations (ADCO), for the purpose of retrieving the completion and ultimately re-completing the well.

The 382ft section of blast joints combined with scale build up in the 2-7/8″ completion tubing above the production packer made it difficult to jar and unset the packer and retrieve the completion. The decision was made to cut the blast joint as close to the packer as possible. Several challenges prevented the use of a conventional electric-line deployed chemical cutter service, which include the 85 degree deviation at cutting depth, scale build up preventing accessibility to the target cut zone, the Dual Completion design removed the ability for tubular tension and annular pressure which reduces the chances of noting the telltale indications of a successful cut.

A coiled tubing deployed motor-assisted tubing cutter assembly, preceded by a scale cleanout tool string, were mobilized and successfully completed the objective despite the challenges most notably the wall thickness of the blast joint and deviation at cutting depth. This allowed ADCO to proceed with their workover program.

Proper planning, effective application design and pre-job testing were paramount to the success of the operation. No previous history of any blast joint cuts, therefore this successful cut, coupled with the highly challenging well conditions, demonstrates the ability to conduct future rig-less thru-tubing cutting operations in a similar fashion, reducing operators rig time and associated costs. The technical contribution of this successful test and subsequent job application has potential to save operators a substantial amount of rig time as cost savings by conducting the pipe recover operations as described.
Solving Stick-Slip Dilemma: Dynamic Modeling System Significantly Reduces Vibration, Increases ROP by 54%
Authors: Rahman Norain Abd , Mohaideen Azlan , Bakar Farah Hanim , Tang Kien Hoe , Maury Radha , Cox Paul , Le Phi , Donald Hugh , Brahmanto Edwin , Subroto Bramanta
Published: November 2012

In mid 2010, Petronas Carigali (PCSB) initiated a drilling campaign of a green field development at the Malay Basin, offshore Peninsular Malaysia. The operator is required to drill a borehole through a challenging interbedded formation with hard streaks calcareous to access natural gas reserves in one of the fields. In two development wells, stick-slip reached an unacceptable level increasing the risk of tool failure while driving up field development costs. The operator required an analysis methodology to ascertain the root cause of drilling dysfunction to optimize the bottom hole assembly (BHA) design and drilling parameters to mitigate vibration and improve drilling performance. To solve the problem, a finite element analysis (FEA) based modeling system was employed to analyze application details from the previous two wells and derive an improvement scheme.

Drilling dynamics data and logging information was collected along with operating parameters, mud logs and PDC bit dull grades. Additional problems were identified included hole washout, insufficient WBM lubricity and issues with a reaming stabilizer. An advanced rock-strength analysis system was used to determine unconfined compressive strength (UCS) of the interbedded formation.

Once all issues had been identified, the model was calibrated and readied for dynamic simulation. A variety of BHA configurations and PDC bits were run under different drilling conditions and operating parameters. The results of the simulations provided sufficient insight to the cause of the high levels of lateral and torsional vibration.

Using the knowledge gains, engineers selected the most appropriate PDC bit and BHA configuration. An optimum range of operating parameters with different weight on bit/revolutions per minute combinations were provided to field personnel to ensure the highest possible rate of penetration (ROP) and still remain in the established low vibration window.

The modeling effort proved successful and the third well was drilled with significantly lower torsional vibration compared to the first two wells. This paper will detail the collaboration and integrated approach of the service company in determining vibration issues and solving the problem, hence enhancing the drilling performance of upcoming wells.
Digital Rock Physics and Challenge in Formation Evaluation of Carbonate Reservoir, Case Study
Authors: Gibrata Muhammad A , Ayoub Mohammed R , Kalam M Zubair , Ali Basioni Mahmoud , Al-Amrie Omar Y. , Hendrawan Irfan , Lopez Oliver
Published: November 2012

A project study has been performed in order to evaluate a number of reservoir characterization and petrophysical parameters using Digital Rock Physics (DRP) technology in complex carbonate reservoir, on-shore Abu Dhabi. High-resolution images (X-ray micro-tomographic) of the rock's pores and mineral grains were obtained, processed and the rock properties were evaluated by numerical simulation of the physical processes of interest at the pore scale.

The selection of core samples in carbonate reservoir was performed with considering reservoir rock type, logs and routine core analysis data for validation and application phase. A set of special core analysis (SCAL) data were acquired earlier on the core samples in different carbonate reservoir rock types of varying levels of heterogeneity, lithology, porosity, and absolute permeability. This set of measurements formed the baseline for our validation study, then similar DRP approach and improvement is applied for non-SCAL cores. This process is used in DRP study to evaluate cementation exponents ‘m’, saturation exponents ‘n’, water-oil relative permeabilities, capillary pressures and elastic parameters such as compressional/shear wave velocities.

An integration of core and logs data in particular carbonate reservoir has been used to provide accurate and reliable results in the validation phase of DRP. It has been observed in DRP that connected micrite phase conductivity contribution has been determined for improvement approach by assigning a finite conductivity σmic to the micrite phase to get reliable formation factor, cementation and saturation exponent. DRP and core J-capillary were integrated to provide reliable saturation-heights in this carbonate reservoir. The integration of formation evaluation in this case study has provided improvement, reliability in DRP results for formation evaluation and the potential to improve the quality and timeliness of carbonate reservoir characterization.
Integrated Reservoir Characterization of an Upper Kharaib Carbonate Reservoir from Onshore Abu Dhabi (UAE)
Authors: Rebelle Michel , Duval Christine , Munoz Véronique , Lescoeur Maurice , Rousseau Mathieu
Published: November 2012

More than 30 years of experience in Middle-East carbonate reservoirs has allowed TOTAL to propose an original integrated workflow to characterize sedimentary and petrophysical properties from core and log data in order to populate, propagate and consequently predict the reservoir behavior within a geomodel.

An onshore field from Abu Dhabi has been recently studied with focus on the Upper Kharaib formation. Based on a detailed sedimentology and diagenesis investigation on cores, Petro-Geological Groups (PGG) are defined from both sedimentology, petrophysics, and associated logs responses. Comparison of PGG with Petrophysical Groups (PG), built from discriminant CCA and Pc data through objective statistical contingency and non-linear loops, strengthens the geological significance of the PG which can be considered as static rock-types.

Saturation laws defined from Pc plugs are thenafter compared with Sw resulting from preliminary quantitative interpretation as additional control of consistency between coresand log data.

Supervised facies modelling allows for the vertical distribution of these PGG throughout the non-cored intervals.

Permeability modelling is also an important step in order to deliver a permeability field within the geomodel. This small scale permeability (issued from the cores and logs) is compared with large scale permeability (from well tests) to insure reconciliation between the two scales.

PGG maps are delivered for each reservoir layer, associated petrophysical properties can be consequently propagated in 3D.

This powerful integrated workflow, relying on a comprehensive integration of all available data at different scales, has been successfully applied for geomodelling issue, allowing for both the understanding and the prediction of petrophysical properties distribution, with a strong relationship between Petrophysics and Geology at core and log scales. This approach gives significant support for the defining and capturing of key flow units heterogeneity and distribution.
Managing the Corrosion Impact of Dense Phase Co2 Injection for an EOR Purpose
Authors: Bonis Michel
Published: November 2012

A review of the main corrosion issues and of the associated corrosion control methods is made in a situation where CO2 is injected as a dense phase at high pressure for an EOR purpose on oil fields. Two distinct sources of CO2 are considered, either from produced gas or from flue gas, i.e. with more detrimental impurities being present.

The use of CO2 from flue gas requires that the so-called NOx and SOx are removed as soon as possible to prevent very serious corrosion problems or very stringent dehydration requirements. Even more constraining can be the necessity to remove the oxygen: although the presence of oxygen is not critical on the injection side, its eventual breakthrough to production facilities will pose dramatic corrosion problems on both C Steel and CRA facilities. As a consequence, until it can be demonstrated with a high level of confidence that this oxygen is totally consumed in the reservoir before reaching producing wells, a prudent approach consists in removing it from the injected CO2 down to about 100 ppm mol.

Apart from these particular aspects related to the use of flue gases, no serious and unconventional corrosion and mitigation difficulty is foreseen on the CO2 injection side when only CO2 is injected. In particular, the dense phase network can be designed in C Steel as long as no free water may separate from the dense CO2. This condition is quite easy to assure in most cases, thanks to the high water solubility in CO2 at high pressures. On the other hand the injection of a mixture of produced water and CO2 at high pressure obviously poses more serious corrosion issues requiring a CRA network along the whole injection network subjected to the mixture.

The proper evaluation of all these corrosion aspects finally requires having in hands the most relevant prediction models, not only in the corrosion area but also in the thermodynamics of dense CO2 mixtures with impurities and in the reservoir modeling area: it is indeed essential accurately predicting how the injected products will move back to production facilities and possibly impact the production side.
A New Fracture Gradient Prediction Technique That Shows Good Results in Gulf of Guinea
Authors: Oriji A. Boniface , Ogbonna Joel
Published: November 2012

One of the major challenges of drilling and completion of oil and gas wells is the uncertainty in the formation fracture gradient and the fracture pressure. It is not uncommon that many drilling companies have spent money, resources and time in drilling and completing wells that should have been simply and optimally done. Fracture gradient evaluation constitutes one of the essential parameters in the pre-design stage of drilling operations, reservoir exploitations and stimulations. Several calculation methods and computer models have been presented in the literature for different regions of the world. Most of these techniques were based on either parametric or empirical correlations, which required a prior knowledge of the functional forms or the use of empirical charts which were not very accurate.

This paper presents an innovative method of predicting formation fracture gradient for Gulf of Guinea region. A combination of "Mathew and Kelly" correlation, "Hubbert and Willis" correlation and Ben Eaton mathematical models were used in developing the simplified technique based on field data from the Gulf of Guinea. The model compared favorably with the existing fracture gradient results in the Gulf of Guinea with less than 1 % deviation from other correlations thereby saving the rigors and time in using tables, charts and other long techniques. Although the method was developed specifically for the Gulf of Guinea, it should be reliable for other similar areas provided that the variables reflect the conditions in the specific area being considered.
Innovative Scheme for Crude Oil Stabilization Using Condensate
Authors: Agrawal Dinesh , Huda Badrul
Published: November 2012

For a new sour field development, the scheme for crude oil stabilization is designed using condensate as stripping agent in the crude oil stabilizer in place of conventional scheme using sweet fuel gas. The article discusses the scheme and its advantages compared to other industry practice of ‘Reboiled Stripper’ for Crude Oil Stabilization.

The design is based on splitting of gas condensate produced during gas compression in to heavy cut and lights in a condensate splitter operating as a distillation column. The lights are recycled back in to the gas compression for gas injection while heavy condensate is vaporized and used as stripping agent in crude oil stabilizer.

The benefits are higher oil volumes with some improvement in oil API achieved through ability to mix higher fraction of the condensate produced in to oil, while maintaining Reid Vapor Pressure (RVP) and Hydrogen Sulphide (H2S) Specifications for oil export.

The scheme eliminates light condensates drying and pumping for injection in to reservoir as it mixes it with gas for injection and a common gas drying and compression system can be used for injection in to reservoirs. Also instead of boiling crude at higher temperatures in the reboiler of crude oil stabilizer which is the case for the ‘Reboiled Stripper Scheme’, clean condensate vapors are used for stripping H2S and light hydrocarbons in crude stabilizer with operations at near 100°C.

This will reduce the system fouling while providing higher plant availability by eliminating reboiler from the Crude oil Stabilizer. The estimated Capital Cost is lower in comparison to other schemes.

Thus the design gives a simplified scheme for simultaneous processing of condensate with crude oil stabilization, producing oil in quantity and specification similar to the ‘Reboiler Option’ while providing additional bebefit of lower CAPEX with higher plant availability.
Evolution of the Smart Production Testing Strategy in ADMA-OPCO
Authors: Al-Hosani M. A. , Khan M. N.
Published: November 2012

With time increasing maturity of hydrocarbon reservoirs is adding more challenges to reservoir management strategies. To enhance the understanding of complex hydrocarbon recovery mechanisms, frequent production testing programs have become a crucial part of the reservoir management cycle.

Abu Dhabi Marine Operating Company (ADMA-OPCO) has been continuously working on improving its offshore production testing capabilities to bridge the gap between the current practice and the increasing demand for production testing.

In this regard, a multidisciplinary taskforce evaluated three different options: Refurbishment of the existing production testing facilities, addition of a Test Vessel in the mobile testing fleet and the installation of permanent Multi Phase Flow Meters (MPFM) on different wellhead towers.

Based on the operational flexibility, better measurement accuracy and the low operating cost, the installation of the permanent MPFM on different wellhead towers was qualified as the most viable option. This strategic decision brought a significant gain of 36% in the production testing performance in the first year of implementation (2011).

The aim of this paper is to highlight the key milestones from a real implementation case during the process of adopting the smart production testing approach by ADMA-OPCO, which can be used as the reference guide for different oil operating companies that would be willing to take up the similar practices.
Robust Maximum Reservoir Contact Pilot Well Design, Optimization and Implementation for Development of a Giant Oilfield
Authors: Khedr Osama , Al Marzouqi M. , Jackson Alfred , Ibrahim Muhammad , Nadeem Muhammad
Published: November 2012

The first Maximum Reservoir Contact (MRC) wells for a major operating company offshore Abu Dhabi have been successfully designed and implemented. In this paper, the design, optimisation, piloting, field implementation, and post-job field data evaluation for the most critical well are discussed.

The re-development strategy for the company hinges on the move to an islands-based development concept. This concept dictates that a significant number of wells be extended reach, long horizontals to maximize reservoir contact and exposure.

The increased reservoir exposure will translate proportionally to accrued production (or injection) benefits and value, balanced reservoir sweep, and maximizing recoveries.

Hundreds of these MRC wells will be ultimately needed, to maximize recovery and drive the field daily production output from the current level to an increase of at least fifty per cent. However the challenges of designing, drilling and completing these complex wells are new to the operating company.

The operator embarked on a program of drilling pilot wells with a view to establishing new learning and understanding, which translates into efficiently designing, deploying and operating these wells for the field re-development.

The paper shows the methodologies employed for one of these pilot wells, right from the concept stage through to the modelling, design and optimisation. It also shows how operational considerations were fed into the optimisation workflow, and how the resulting design was implemented in the field.

The obtained field measurements such as resistivity, fluid mobility, production logging, production rates were compared to the initial design and performance forecasts, and excellent conformance is demonstrated, further validating the robustness of the implemented designs.

The paper highlights the lessons learnt from this exercise, and also proposes a recommended methodology for approaching and adopting the design and implementation of advanced wells, within oil and gas producing assets.
Interfacial Tension (IFT) and Surface Alteration Interplay
Authors: Stukan Mikhail , Abdallah Wael
Published: November 2012

The two main parameters required to assess an enhanced oil recovery (EOR) technique in terms of its efficiency are interfacial tension and surface (wettability) alteration. The impact of these parameters on recovering what is left in the reservoir is crucial. With the current interest in brine injection as a potential-EOR method, the role of IFT and wettability alteration needs better understanding. In this study, a theoretical model is developed to evaluate the impact of both parameters. The results of this study indicate that salinity injection affects more surface wettability rather than interfacial tension.

Conventional techniques of contact angle measurements on reservoir rocks at downhole conditions are very complicated. They are highly sensitive and require good core preservation and preparation. We propose a protocol to measure contact angle dependence on brine salinity, which includes a single contact measurement in rock/brine/oil system using fresh water and a set of less complicated measurements in brine/oil and rock/brine/air systems. The results of our predictive protocol for contact angle measurements are in very good agreement with conventional experimental measurements using glass/brine/dodecane system. The fact that simple contact angle measurements on the surface in air are required to calculate contact angles at different salinities makes the utilization of this protocol very attractive and less sensitive to surface preparation and its complexity.
The First Successful Field Demonstration of Alkaline Surfactant and Polymer Flooding through Thin Layer
Authors: Cheng Jiecheng , Dianping Xu , Xinguang Sui , Hongwei Wang
Published: November 2012

The Alkaline Surfactant and Polymer (ASP) demonstration block has 49 injectors and 63 producers, with area of 1.92 km2. The target zone has bigger reservoir span and consists of many thin layers with narrow fluvial sand body, smaller thickness, lower permeability, higher clay contents. The layers combination and well spacing have been determined basing on the fine geological research and existing ASP flooding performance. The ASP formula, injection parameters and system slug combination are determined through the lab research and numerical simulation.

Field data show injection and production rate maintain an acceptable level at the decline of 7.91and 17.1% in volume respectively. Producers have good response with the average WC decreased from 96.2 to 78.6% for center wells. Profile measurements results show that, for higher permeable zone, the adsorbing thickness has been improved by 13.4 and 7.1% respectively by contrast to water and polymer flooding, and for lower permeable zone, it is 46.1 and 37.1 respectively. The analysis on produced oil shows that, during ASP injection process, the C16-38 content has increased gradually from51.9 to 63.7.This result indicates that the oil displacement efficiency has improved. The ultralow IFT between water phase and oil phase has been incounted, whose liquid was produced from 28 wells, which are among 36 total center wells. That states ultralow IFT has been achieved widely in the reservoir. At present, chase water has been injected, with WC 92.0% and incremental oil recovery 26.0% OOIP. The ultimate oil recovery predicted to be 28.0% OOIP with production cost at $24.6 / bbl.
Produced Water Re-Injection, a Successful Strategy, from Pilots to Field Wide Implementation
Authors: Katchi K. , Remfsío Luís , Abdullah Dalia
Published: November 2012

As ADCO's oil fields mature, produced water increases. ADCO forecasts that the produced water may increase in the next 25 years as much as 10 fold (in excess of 600,000 BWPD by 2020 and more than 1,000,000 BWPD by 2027). On the other hand, in order to support the reservoir pressure, ADCO is sourcing brackish water from deep aquifers (D, S and U). The produced water is then disposed back into aquifer S. This practice has high financial and environmental costs:

In order to strategically manage increasing volumes of produced water as the main oil producing reservoirs reach maturity, ADCO started pilots to re-inject untreated produced water in three fields in early 2000: Field 1 in 2002, Field 2 in 2010 and Field 2 in 2003.

Positive pilot results in Field 1 led to field wide expansion of the Produced Water Re-Injection (PWRI) into one the oil bearing reservoirs and it was included in the Full Field Development Plan (FFDP).

A pilot for re-injecting untreated PWRI is currently running in Field 2 for the past 16 months at a rate of more than 20,000 bwpd. Positive outcome so far led to raising funds to extend PWRI network to achieve re-injection rates of 50,000 BWPD into one of the oil bearing reservoirs in this field.

The pilot for Field 3 was plagued with interruptions since the start caused by PWRI system material integrity issues which did not allow concluding so far whether untreated PWRI re-injection into one of the oil bearing formations is achievable. In order to address this situation, corrosion mitigation measures both for relevant surface facilities and downhole completions are being implemented and in parallel, an integrated coreflood testing/geomechanical properties study is on-going to assess the degree of treatment required to allow re-injecting produced water cost effectively in the most permeable oil bearing reservoir in this field.

ADCO's approach to managing increased produced water rates through pilots and learning from rock matrices testing/studies shows that managing field wide PWRI systems in a cost effective and environment friendly manner is achievable if planned sufficiently in advance and executed properly.
Chemical Incompatibilities between Formation Water and Injection Water; Comparison between Modeling and Site Observations in Fields Operated by TOTAL
Authors: Baraka-Lokmane Salima , Hurtevent Christian
Published: November 2012

This study presents examples of fields operated by Total where are observed incompatibilities between reservoir formation water and injected seawater. In these examples, we show the scatter between risk estimated by modeling and site observations.

The prediction of calcium sulfate deposits identified by modeling is not valid as the scaling problems are either non-existent or considerably less serious than expected. With respect to the precipitation of barium sulfate, the risk estimated by modeling is always much higher than reality. In this study information are provided that will allow us to have more realistic scaling predictions in the future.
Permeability Scalar from Seismic-Based Fracture Prediction
Authors: Matarid Tarek , Afia Mohamed S , Al-Hossani Khalil I. , Amer Mohamed M.
Published: November 2012

The post stack seismic fracture prediction method consistently shows fractures that are similar to those indicated by well methods and therefore seismic can be used to detect natural fractures between wells. The confidence in the seismic fracture prediction method's ability to capture information about fracture in Carbonate reservoir has increased if the well data are accurately integrated.

This paper describes an approach in characterizing fractured reservoir of upper Jurassic Carbonate using seismic structure attribute maps. The ultimate objective of this study was to attempt to map permeability scalar inter-well for the contribution to the simulation model and the subsequent development plan of an oil field offshore Abu Dhabi.

The studied field is not developed, but the subject reservoir was sparsely sampled with logs, limited well tests, limited cores, one FMI and one full waveform sonic. We have studied and analyzed the well based fracture detection results. The well analysis included FMI study, Stoneley waveform, well production tests and core images. The likely fractured layers were identified at the lower dense part of the reservoir. Well seismic synthetics were generated and the fractured layers were found to exist in less than one cycle.

Following the fractured layers identification in the seismic cube, an intensive seismic attribute analysis was conducted. The studied seismic reservoir attributes includes spectral decomposition analysis of Amplitude and Phase followed by structure attributes such as Coherency, Curvature, Amplitude change in X or Y and Azimuth. Here we report and analyze the fracture prediction results for Carbonate reservoir.

A consensus results from borehole ellipticity, Seabed ramp and near Seabed seismic structure map versus known regional stress will be presented as guide of current stress direction. Based on the extracted fracture map from seismic, the current stress direction and the well permeability scalar, a 1km x 1km permeability scalar map was generated.
Innovative Modelling Method of Diagenetic Overprints in Carbonate Reservoirs
Authors: Planteblat Caroline , Massonnat Gérard , Virgone Aurélien , Caline Bruno , Pabian-Goyheneche Cécile
Published: November 2012

Modelling products of diagenetic processes in carbonate reservoirs is still a challenge since both stochastic and physicochemical simulations cannot easily reproduce complexity of features generated by those processes. An alternative way to modelling diagenetic overprints deals with an innovative methodology based on process-like simulation of the fluid-rock interaction and its effects on reservoir properties. The principle of the method is related to a lattice gas automata used to mimic the diagenetic fluid flows and to reproduce the diagenesis effects through the evolution of both mineralogical composition and petrophysical properties.

This new modelling approach is well adapted to handle dolomitization processes and was applied on two case studies.

In the Urgonian carbonates, (Barremian-early Aptian) characterized by a platform facies predominantly of rudists and bioclastic/ooid grainstone (S.E. France), five main diagenetic stages have been identified. The 2D modelling focuses on dedolomitization features located on parasequence boundaries.

In the Venetian platform (Lias, N.E. Italy), data collected show four diagenetic stages. The main one, related to dolomitization along fractures, is called per-ascensum dolomitization. Three of the diagenetic stages have been simulated on a 3D depositional model previously filled with initial facies and original petrophysical properties.

The simulations of the Urgonian series lead to generate dedolomitized bodies related to surface boundaries that match those identified on the outcrop. Calibration on actual data of diagenetic parameters used for per-ascensum dolomitization modelling of the Venetian platform also enables to reproduce and to visualize the displacement of dolomitizing fluids in the fracture network and within the stratigraphical layers.

In both cases, the evolution of the mimetic diagenetic fluid effects on mineralogical composition property can be followed through space and numerical time, which helps to understand the heterogeneity of reservoir properties.

This method enables the modelling of diagenetic overprints without any explicit physicochemical equation in any carbonate reservoir for which diagenetic products are generated through fluid transport.
Under-Balanced Drilling: A Game-Changing Technology for the Development Strategy of a Giant Carbonate Reservoir
Authors: Khan Karim , Aziz Khalid Abdel , El Baramawi Mohamed , Mueller Klaus , Mata Tomas , Al Hassani Khaled
Published: November 2012

It is fundamental to pilot and deploy IOR/EOR initiatives to improve recovery from petroleum reservoirs using cost effective methods, ensuring a continuous supply of production that would meet the ever-increasing demand for energy.

Under-Balanced Drilling (UBD) technology proved worthy as a valuable initiative in the redevelopment strategy of a Giant Carbonate reservoir located in the Middle East. It improved well deliverability especially in low permeability reservoir zones. The strategy for this has been to deploy 3-4000 feet laterals to maximize reservoir contact to such tight units or drill as far as possible to have maximum flow input/productivity. Horizontalization (non-UBD), together with stimulation has been going on for many years with mixed success as recent production log surveys showed negligible contribution from several wells completed in these low permeability units.

In 2011, well-X was drilled underbalanced to assess the value of this technology in augmenting productivity and improving reservoir characterization. Significant improvement in Productivity Index was accomplished by minimizing damage from drilling and completion operations. In addition, considerable knowledge was acquired from Flowing While Drilling (FWD) data and multi-rate tests in four segments of the production zone. Real-time geosteering was actively used to account for changes in the reservoir architecture.

Analysis of the FWD data has derived in new understanding of the dynamic nature of the reservoir's South-central region, highlighting sectors of high permeability, fractures, tight areas, different pressure regimes and varying fluid composition. Furthermore, despite the innovative nature of the technology, drilling and completion was very well controlled by the Well Construction teams, resulting in costs not significantly higher than normal over-balanced wells.

The enhanced reservoir knowledge that UBD delivers as shown from well-X will result in improved recovery efficiency and possible delayed water production. Moreover, it is a lead value improvement technology that will meet strategic business objectives with minimum risk and lowest Unit Technical Cost.
Facies Characteristics of Aptian Formation within the Regional Stratigraphic Framework of a Giant Carbonate Field in the Middle East
Authors: El Wazir Zinhom , Al Madani Noura , Müller Klaus
Published: November 2012

Facies and their distribution in space are key building blocks to determine the depositional architecture of hydrocarbon reservoirs. For this reason, the unified high resolution facies and sequence stratigraphy boundaries are needed to constrain facies architecture and their properties distribution for constructing the 3D static and dynamic model. A comprehensive facies analysis and modeling within the established stratigraphic framework, was conducted to reduce the uncertainty in correlating and building-up the architecture between wells.

Over 30,000ft of core data from 155 wells and their log data are used in integration with the seismic interpretation. Knowledge of the facies results in a better correlation, used then to generate a total of 47 spatial facies maps. Some facies are combined to facies associations (FA) maps, representing the FA at each sequence boundary in its sequence package. For each selected interval, the dominant FA observed in individual wells has been correlated; preserving the general evolution of the depositional environment and the sequence stratigraphy framework. These maps are used to constrain the variograms for the petrophysical properties distribution in terms of orientation and ranges.

A conceptual facies model was created based on facies distribution following an evolving platform to basin topography during transgressive (Apt1&Apt2), early-highstand (Apt3), late-highstand (Apt4a&Apt4b), and composite lowstand (Apt5) phases of carbonate platform development during the Aptian. The best reservoir quality is dominated by dissolution related mouldic and vuggy macropores. The grain supported textures demonstrate better overall reservoir quality as a result of more abundant interparticle and intraparticle pores and enhanced macro-vuggy porosity created by leaching process. Some poor reservoir quality is observed in grainy facies due to cementation.

A detailed understanding of the core-based facies description/analysis is required for identifying the reservoir properties and its relation to rock-texture; leading consequently to the rock-flow-units in the dynamic model.
Human Factors in HSE Performance
Authors: Misra Achal
Published: November 2012

‘Safety First,’ the motto of petroleum industry has been in focus since early 20th century evolving HSE considerably and as of today, we have industry best HSE practices nevertheless accidents still happen. A welder lost his life after he entered inside a 30" pipe to inspect a weld joint. This is despite safety alert being widely circulated two weeks prior for a similar accident happened elsewhere. Are accidents inevitable or preventable?

‘Preventable,’ would be the intuit answer but when prodded deeply with a psychological perspective the scenario apparently leaves an ounce of doubt, ‘was it inevitable?’ To demystify the fatalistic thinking, a psychoanalyst's perspective is required to unveil the latent human factors that lead to unsafe acts. Even the safety regulations cannot rein human decision making processes which are affected by cognitive biases such as intuition, overconfidence, illusion of control, confirmation, complacence and hindsight. Under such constraints, it is no surprise that incidents reoccur whereas companies search for compliance gaps in HSE implementation.

Taking into account the case study of fatal welder accident, this papers explores human error and its influence on performance level, unveils human brain functioning, describe briefly five cognitive biases that influences unsafe acts, conjure the fatal welder accident with plausible biases, and concludes calling for more efforts to increase the awareness of cognitive biases and develop a safety culture helping to prevent incidents and improve HSE performances.
China's Early Stage Marine Shale Play Exploration: A Deep Asia Pacific Region Horizontal Multiple-Stage Frac: Case History, Operation, and Execution
Authors: Lv Zonggang , Wang Lin , Deng Sufen , Chong King Kwee , Wooley James S. , Wang Qiang , Ji Peng (Marks)
Published: November 2012

During the past five years, shale gas developments have changed the game for the US natural gas industry. Globally, shale exploration activities are also increasing. China is in the early stages of exploiting the world's largest reserves of shale gas resources while attempting to cope with increasing energy demands.

This paper presents a case history of applicable technology currently used in North America for initial attempts at shale gas exploration in China. This case study is the first Cambrian age marine shale well in the Qiongzhusi formation located in the shale-gas-rich Sichuan province.

Many technologies were brought from North American shale gas applications for this well (Chong et al. 2010). This study describes the technologies used to drill and complete the targeted shale gas formation and guide the completion and stimulation design. The target formation was drilled horizontally and the casing was cemented. The formation was then stimulated with multiple stages after full integration of data from geologic, geomechanical, petrophysical, and core analysis, which aided in the fluid and proppant selection, proppant concentration, and the designed injection rate. A diagnostic fracture injection test (DFIT) was performed before the main treatment to confirm fracture gradient, closure, pore pressure, system permeability, and leakoff. Microseismic mapping was also used, which proved to be valuable when planning and assessing the fracturing results.

Currently, the well is flowing gas at rates comparable to early production time in a typical North American shale gas well with a similar type of completion.

This case study serves as an example of successful implementation of proven technology outside of the North America shale gas market. Continued projects such as this one are the predecessor to full-scale development of shale gas and have helped shape the abundant gas supply currently in the United States. Additionally, these types of projects are necessary to help China improve their future outlook on gas supply.
Best Practices in Turnaround Management
Authors: Festus Roy
Published: November 2012

1.Introduction

One of the Best Practice in Turnaround (TAR) Management is to have an effective system in place to monitor TAR Performance. Balanced Score Card (BSC) is an effective tool for measuring performance of a TAR project from different project perspective considering all management objectives.

2.NEED FOR BSC:

Today business is being done in a very competitive environment. ■ HSEQ standards are very stringent. ■ Compliance to Environment standard is very important. ■ Negligence, lack of knowledge and oversight is not acceptable. ■ Business needs to be carried out with SMART Targets (Specific, Measurable, Achievable, Realistic, Time bound). ■ Performance needs to be evaluated at every step from all project perspectives and management objectives.

To enssure excellence in TAR management, Takreer adopts BSC concept to evaluate TAR performance. This BSC incorporates all TAR objectives like inventory optimization, material availability, timely award of Contract, timely completion, quality and cost control with prime emphasis on HSE. The performance can be graphically represented as shown in slide – 2 of the presentation.

No technique will work unless you believe in it, own it and each individual makes it a part of his belief system.
Reducing Energy and Emissions through Predictive Performance Monitoring System
Authors: Zamzam Montaser M. , Reddy Vijaya B. , Al Bisher Khalid , Mather Ian
Published: November 2012

Air emissions from combustion sources are monitored by different techniques such as use of emission factors, engineering calculations, periodic stack monitoring, Continuous Emission Monitoring Systems (CEMS) and Predictive Emission Monitoring System (PEMS). CEMS despite being seen as best practice but is expensive and requires extensive maintenance. PEMS has become recently popular in estimating real-time emissions from various air pollution sources using measured process parameters. Abu Dhabi Company for Onshore Oil Operations (ADCO) based on a wide techno-economical survey had chosen PEMS to monitor its emission and maintain compliance report on air quality as per the requirements of Abu Dhabi National Oil Company ADNOC. In addition, ADCO's innovation ensured additional modules to monitor energy performance and also provide a platform for maintaining energy and emission KPIs. ADCO commissioned the first pilot PEMS in Bab field in 2010 covering all emission sources and typical units of the major energy users such as gas turbines, heaters, oil export pumps, water injection pumps and gas compressors.

PEMS real-time information and remote access through web helped in taking prompt corrective actions to control equipments and optimize use of fuel which resulted in subsequent reduction of energy and Green House Gases (GHG) emissions besides compliance assurance against ADNOC's air emission limits for process units. PEMS was proven to be as accurate as the hardware based CEMS over the entire range of operations and therefore it can be readily applied for tracking air emissions and energy efficiency from gas turbines, heaters at marginal cost. In addition to providing data for emissions compliance, ADCO was able to use the PEMS to optimize machinery operation for better performance and efficiency, and consequently reduced emissions.

This paper demonstrates ADCO's success in integrating energy performance and emissions reporting in one simple yet effective solution. The paper further describes how the PEMS was able to integrate data from various plant sources into one reporting system while at the same time meeting ADCO IT protocol.
Modeling of Asphaltene Precipitation in Heavy Oil Reservoirs Using Hydrate-Flory-Huggins Model
Authors: Nikookar M. , Sahranavard L. , Roayaei E. , Emadi M. A. , Pazuki G. R.
Published: November 2012

In this study, an equation of state (EOS) was developed based on volume correlation in predicting phase behavior of pure fluids. The Average Absolute Deviations (AAD %) of the modified EOS are 1.116, 4.318 and 2.93 for the saturated pressure, liquid density and vapor volume, respectively. The results of the proposed EOS are compared with those of Peng-Robinson (PR) and Modified Peng-Robinson (M-PR) equations of state. In the next step, the modified EOS was coupled with the hydrate-Flory-Huggins Gibbs energy model in order to predict asphaltene precipitation phase behavior in the crude oil. The results show that the hydrate-Flory-Huggins model can more accurately predict asphaltene precipitation than the original Flory-Huggins model.
An Improved Reservoir Understanding through the Use of a Unique Platform for Reservoir Management and Simulation: Application to Gas Movement Understanding in a Gain Field
Authors: Bashatah Lafya , Helmy Mohamed , Draoui Elyes , Asakawa Kazuhiro , Graves T. Hunter , Alurkar Kaustubh , Jayanti Shekhar , Giordano Ronald M. , Bhangale Amit , Limaye Nilesh , Raut Bipin
Published: November 2012

Streamline analysis coupled with finite-difference simulation provides a novel effective approach for an integrated reservoir management. The output from the existing compositional reservoir model was processed to generate streamlines from the finite-difference simulation. Reservoir management data, historical well performance data, calculations from streamline bundles, and novel performance diagnostics are integrated to optimize the field management and maximize oil recovery. Simulation and field data are combined to give an integrated understanding of the reservoir leading to smart reservoir management. Powerful streamline analysis is being used to help optimize injection and increase recovery efficiency. Real field data and model data are being analyzed to identify the areas of upswept oil and opportunities to improve the reservoir performance. This new methodology workflow is implemented in a user-friendly and intuitive way, giving more time for analysis and integration then data management.
Impact and Lessons of Using High Permeability Streaks in History Matching a Giant Offshore Middle East Carbonate Reservoir
Authors: Brantferger K. M. , Kompanik G. S. , Al-Jenaibi H. M. , Dodge W. S. , Patel H.
Published: November 2012

A new generation geologic model for a giant Middle East carbonate reservoir was constructed and history matched with the objectives of creating a model suitable for full field prediction and sector level drill well planning. Several key performance drivers were recognized as important factors in the history match; 1) unique carbonate fluid displacement; 2) data validation and horizontal well trajectory issues; and 3) distribution of high permeability streaks. Ultimately a full field history match consisting of more than 1000 well strings and several decades of history was achieved using detailed distribution of the high permeability streaks, while honoring measured core poro-perm relationships, lab-validated displacement curves, and well test data.

This paper discusses the role of the geometry and the vertical distribution of the high-permeability streaks in the history matching of a giant offshore carbonate reservoir. Specifically, the modeling of the high-permeability streaks – which consist of thin rudist and algal rudstone, floatstone, and peloidal grainstone, with abundant, well-connected inter-particle porosity - became possible after extensive revamping of the reservoir rock type model, updating well descriptions, and a detailed zonal mapping of the high permeability streaks and dolomitic zones. The areal and vertical model resolution was doubled over the previous models to accommodate the internal sub-layering of the upper four reservoir zones in order to capture the thin (~1.4 ft) high-permeability streaks.

During the history match, local modifications of the high-permeability streaks were the integral part of the feedback loop between the simulation engineers and geoscientists that kept the common-scale simulation model and geologic model synchronized. The final history match was validated by extensive analysis of the models’ vertical conformance as compared to production logs. This approach made it possible to construct a more heterogeneous model than previous models; while honoring both field KH and matrix poro-permeability without local permeability multipliers. The combination of these features provides a higher confidence model of long term well injectivity/productivity.