bluuebunny/crossref_metadata_2025_split huggingface dataset:
From Core to Geomodel Integrated Reservoir Characterization: Example of a Carbonate Gas Field
Authors: Rebelle Michel , Cochet Fabrice , Duval Christine , Caline Bruno , Mabille Cedric , Gapillou Claude 
Published: March 2015

Abstract
A carbonate gas field is presently described throughout an integrated study from sedimentary context to geological model.
Petro-Geological Groups (PGG), integrated combination of sedimentology, diagenesis, petrophysics and log responses, are supporting the maps and trends for the geomodel population. On the other hand, Petrophysical Groups (PG), strictly relying on petrophysical properties, appear to be more pertinent for petrophysical parameters distribution. Petrophysics (porosity, permeability, saturation) will be consequently propagated into the geological model based on a simple relationship between PGG and PG.
With regards to saturation laws, a Wooddy-Wright-Johnson approach is proposed with min-mod-max scenarii, in order to represent the noticeable range of uncertainty, proven to be standard in carbonate environments.
Regarding the facies modeling, a supervised model provides a good result in terms of characterization and propagation of PGG for most of the studied wells whereas an unsupervised model was used to build the PGG crenel log. Furthermore, the Similarity Threshold Method (STM) computed for both models, supervised and unsupervised, highlights the good reliability of the propagation with regards to logs training set.
Permeability modeling has shown the limitation of the methodology for mono-lithological and very heterogeneous carbonate field. The prediction on cored wells, used for the training itself, provides a satisfactory result, but the prediction on un-cored intervals is not reliable. Distributions of permeability by PGs should be only based on the petrophysical synthesis results.
Such an integrated study allows maximizing the consistency and the reliability of the results, in spite of a very complex heterogeneous environment, with evidences of drains and barriers.
Effectiveness of Digital Rock Physical Laboratories In Characterisation Of Heterogenous And Complex Carbonates- A Synthesis
Authors: Mishra Prasanta Kumar , Akbar Bibi 
Published: March 2015

ABSTRACT
The digital rock physics laboratories following the CT and micro CT scan techniques are in forefront and claim to carry out an accurate pore to core scale characterization of carbonate rocks with minimum possible time lapse. They measure the rock properties (porosity, permeability, electrical resistivity and elastic properties), this technique is relatively costly compared to the measurements of physical laboratories but results are obtained faster. It is known that the prediction of petro physical properties of the carbonates and assessment of multiphase flow properties in carbonates are very challenging due to complexity in the depositional processes and various digenetic changes altering the primary and even the secondary fabric of the rocks. A wide ranges of the pore and particle sizes are seen thus making the carbonate rocks heterogeneous and complex and even in a core piece of 4x6 inches a wide variation of various rock properties are noticed.
A synthesis of the data obtained from the output of three digital rock laboratories in measuring the properties of the complex, heterogeneous and tight carbonates has been made and a thorough analysis of the imaging and sampling techniques adopted by them has been critically observed. The results obtained from the high cost studies may not be the representative of the sample and may be misleading if basic assessments are not made properly by the concerned sample analyst. Although the company makes a tall claim of accuracy, the following are the critical factors that the ultimate user needs to be careful about otherwise the true value of the money spent is not obtained.
Unlocking the Limits of Sand Screen Reliability with an Innovative and Self-Adapting Technology
Authors: Yeh Charles S. , Moffett Tracy , Mayer Christian Sebastian Jakob , Bailey Nathan , Howell David A. , Barry Mike D. , Hecker Michael Thomas , Green Annabel , Gillespie George , Hall Christopher A. , McNamee Stephen 
Published: March 2015

Abstract
Sand screens subjected to increasingly complex and challenging environments are pushed to the limit of maintaining reliable sand control. Both preventive and reactive methods have considerably improved sand screen reliability, but the effectiveness of these methods in sustaining production is still limited by downhole uncertainties. Consequently, innovative sand screens are required to enhance sand control reliability, while maintaining operational simplicity. MazeFlo™ is one recent technology innovation from ExxonMobil designed to meet this challenge.
MazeFlo technology takes a self-adapting approach to enhance sand screen reliability. The technology utilizes a redundant sand screen and compartment maze to self-mitigate sand breakthrough caused by screen damage. The sand ingress is restricted in a local compartment without interrupting the overall well production. A 2?" prototype screen has been designed, fabricated, tested, and qualified for field installations.
This paper will highlight the qualification of this new screen through a series of mechanical tests and concludes with a field test designed to subject the screens to an extreme producing environment. The mechanical performance was evaluated under various load bearing conditions including collapse, burst, bending, torsion, tension, compression, and push-off. The results proved that there were no constraints to the self-mitigating capability of this new screen when subjected to this rigorous testing program. The field qualification test was conducted in an existing sand-prone well producing at high local flux to demonstrate screen functionality in an "uncertain" production environment versus a controlled, laboratory experiment. The field test demonstrated successful installation, downhole self-mitigating capability, and sustained sand-free production.
This unique, self-adapting technology unlocks the limits of sand screen reliability and provides an innovative and unique option for sand control completions to sustain production. The dedicated collaboration between operator and service supplier delivers continued success in developing innovative technology from concept to field installation.
Sidewall Coring: Advanced In-situ Freeze-Core Technique
Authors: Arora Aman , Bihani Abhishek Dilip , Padalkar Chaitanya Makarand , Punase Abhishek Dinesh , Patwardhan Samarth Dilip 
Published: March 2015

Abstract
The importance of obtaining a perfect core of a petroleum reservoir is undisputed. Despite tremendous advances in coring techniques, some basic problems remain as challenging as ever. One of these is the coring of unconsolidated formations. Most side-wall cores result in partially damaged cores, totally damaged cores or no core at all, especially in unconsolidated formations. This proposed technique promises to greatly improve the recovery, quality and longevity of the core, thereby resulting in a much better interpretation.
Freezing has long been used to preserve cores on the surface, but never before used in-situ. Here in this technique, part of the formation is frozen before being drilled out. Freeze coring promises to be highly beneficial in percussion side-wall coring, as it increases localised formation strength thus increasing impact resistance. Hence, the chances of recovering the core intact increase significantly.
This paper discusses the science of the proposed process, explains the mechanism and puts forward a new design for coring, which will help bring back virgin cores to the surface. Changes in the current techniques are proposed which is backed by experimental work.
Overall, this work will help determine petrophysical properties of the reservoir to a much higher accuracy while drilling, thus helping in identifying prolific reservoirs.
Results of Sustainable Safety Performance by building Safety Culture in a Multi-Cultural Workforce
Authors: Mataqi Ismail , Adivi Bala Siva Srikanth 
Published: March 2015

Abstract
Demands on the Oil & Gas industry are driving continual improvement in Health, Safety & Environment (HSE) performance, which in turn the business performance of an organization. It has been widely accepted in the industry that a structured safety culture and its implementation coupled with visible leadership and commitment directly affects HSE performance. Developing Safety Culture is a complex process, and yet it is inevitable for any organization to excel. An Organization's safety culture reflects the leadership & commitment, and values that employees share regarding HS&E.
Kuwait Oil Company (KOC), one of the premier Oil &Gas companies in the Gulf region, gives top most commitment to HSE and considers HSE as a key strategic objective of its business strategy. KOC recognized the importance of Safety Culture in not only just delivering the best decisions by the Leadership, but involves commitment to the implementation and practicing, which will form core pillars for establishing very good Safety Culture. KOC strongly believes that Safety Culture coupled with leadership and commitment act as fundamentals to HSE performance, and to business success.
Safety Culture is considered as one of the key constituents for delivering top class HSE performance in Oil & Gas Industry. This is a strong challenge for a company that is truly multicultural, employing more than 40,000 personnel (including Contractors) from over 65 different nationalities, spread through every continent of the globe. This paper describes four indicators of safety culture: Leadership, Two-way communication, Employee Involvement, Learning Culture & Attitude towards blame. These indicators have been chosen after we started saying "How can we implement Company's HSE Management System effectively that creates a culture in which continual HSE performance is achieved and safety is everyone's concern". A review of the existing safety culture was undertaken to identify details of appropriate criteria against which company performance has been assessed. Also it presents the salient findings of the existing phase of the organization (WK Fields of KOC), as a result of above four indicators and results achieved in terms of HSE performance so far.
Waterflood Conformance Control in Heavy Oil, Multilayer Reservoirs
Authors: Kalita Rintu , Ali Ehtesham , Al-Hikmani Salwa Mahmood , Al-mujaini Rahima A. Rauf , Jaspers Henri F. 
Published: March 2015

Abstract
This paper presents the case history of efforts made in managing the vertical conformance in heavy oil, multi-layer reservoirs. The onshore field discovered in 1985 in south Sultanate of Oman is heavily faulted, compartmentalized with multiple reservoir layers of varying permeabilities. The oil is relatively heavy with average viscosity of 60–150 cp, density of 22 degree API with low GOR. The waterflood was piloted in 1993 by adopting a 5 spot pattern. Full field waterflood was implemented in 1999.
As the waterflood in this field is characterized as one with poor vertical conformance due to varying layer permeabilities, effective conformance control is expected to result in more efficient waterflood by increasing volumetric efficiency and hence potentially increasing the recovery by 5%.
It is relevant to highlight that one dominant layer (highest permeability) contributes to most of the current oil production. Hence, profile modification changes need to keep a balance in enhancing production from other layers while not adversely affecting the contribution from this dominant layer. A multi-pronged strategy to tackle the vertical conformance control challenges has been adopted in the form of both mechanical and chemical profile control methods. The mechanical methods are to install (a) selective completion with sliding sleeves in producers, (b) dual injection through tubing and annulus after frac of low permeability layer, (c) selective completion in injectors with regulator valves/ ported sleeves, (d) casing patch, bridge plug, cement squeeze in producers and injectors. The chemical methods are (a) profile control with polymer gel in the injectors, (b) fracture shut-off with polymer-silicate gel in the injector.
As can be expected, the critical success factors in the vertical conformance control strategy are good surveillance data, understanding of interwell layer connectivity/ crossflow, selection of candidate well and remedial methods. The paper summarizes the conformance control strategies, implementation, results to date with lessons and recommendations.

Introduction
PDO operates many heavy-oil fields located in the South of Oman. These fields are clastic reservoirs with multiple layers of varying permeabilities. Water flood is a common practice in the development of these fields due to either lack of aquifer or weak aquifer and low depletion drive energy. However the heavy nature of the oil makes these water flood projects challenging due to very unfavorable mobility ratio between oil and water. Water breakthrough happens very quickly and most of the recovery takes place after water breakthrough. More pore volume injection and ability to produce to high water cut is the key to maximize recovery from these fields. Hence it is essential that the waterflood targets all the hydrocarbon bearing layers between the injector and producer to maximize the recovery of the field.
Overpressures in the Northern Malay Basin: Part 2 - Implications for Pore Pressure Prediction
Authors: Limpornpipat Orapan , Laird Andrew Paul , Tingay Mark Robert , Morley Chris , Kaewla Chaiwat , Macintyre Hamish 
Published: March 2015

Abstract
Examination of plots of sonic velocity against effective stress from the Northern Malay Basin indicate that fluid expansion or another unloading mechanism contribute to the total overpressure in addition to the more commonly recognised disequilibrium compaction mechanism. The aim of this study was to build a pressure prediction model from spatially extensive seismic velocity data. The pressure prediction model was calibrated by sonic velocity data acquired at well locations where extensive pressure datasets as a function of depth were measured using wireline equipment. Analysis of pressure and velocity data from wells in the Northern Malay Basin shows that pore pressure can be accurately predicted from sonic velocity using a modified Eaton approach and the seismic velocity is closely fit by filtered sonic velocity data. This modified Eaton technique requires the derivation of a robust normal compaction velocity trend and the selection of suitable empirical coefficients. The spatial variation of the fitting coefficients of an empirical normal compaction velocity and the empirical Eaton overpressure prediction relationships were assessed for 31 wells. Results show that in the Northern Malay Basin the compaction coefficient varies spatially with the geological structure and the spatial variation of the Eaton coefficient was found to be positively correlated with the magnitude of pore pressure. Accurate pressure prediction from seismic at locations away from calibration wells requires that seismic velocity analysis outputs sufficiently accurate interval velocities at a suitable resolution. The assessment of the accuracy of seismic velocities was performed on pre-stack data for a number of inlines over the study area. Seismic velocities were carefully re-picked and the resulting interval velocity at the well locations found to closely match the filtered sonic velocities. As a result of the remote nature of the seismic measurement there remains some error in the interval velocities predicted from the seismic due to the presence of shallow gas accumulations which affect the transmission of seismic energy and residual multiples in the processed reflection data.

Introduction
Drilling operations for hydrocarbon exploration and development in overpressured formations are potentially hazardous from an HSE perspective and can often lead to difficulties such as kicks, blow-outs, borehole instability issues, stuck pipe and lost circulation (Sayers, 2006). Overpressure occurs when the pore pressure at any given depth exceeds the hydrostatic pressure of a column of water (or formation brine). If the pore fluid pressure magnitude exceeds a threshold dictated by the strength of the rock, the rock will fail and no longer seal the reservoir causing the release and migration of hydrocarbons and the breaching of the trap (Dutta and Khazanehdari, 2006).
Drilling Fluids Challenges in Successful Drilling of Gotnia Formation in the State of Kuwait
Authors: Jasem Al-Saeedi Mohammed , Dakhil Al-Enezi , Arun Rajagopalan 
Published: March 2015

Abstract
Drilling the Gotnia formation in Kuwait has long been a drilling fluids challenge due to its sharp contrast in lithology of salt/anhydrite interfaces. Presence of this salt layer below 13,000 ft. with a thickness of 700–1,200 ft. in deep wells makes this formation more plastic in nature due to high pressure and temperature. There is a fine line between kicks and total loses in this fractured formation. Hole instability, stuck pipe, total loss, well control, acid gases and H2S are frequent problems while drilling this section.
High pore pressures exist, requiring mud weights ranging between 18.5–21.5 ppg. With this mud weight range in salt drilling, there are limited options available with the drilling fluid to ensure bore hole stability. Drilling fluids design, loss control and well control are massive tasks. Mud weight management with the knowledge of formation stresses, maintaining lowest possible rheology and managing the salt dissolution to avoid well bore closure/instability are key factors in avoiding complications in these deep wells.
OBM is utilized to drill this formation due to the insolubility of salt in oil. Historically, this formation was drilled with lower oil/water ratios resulting in high rheology along with higher mud weights causing frequent mud losses and stuck pipes. Maintaining high oil/water ratio helped to overcome the problems associated with rheology and hydraulics. Salt rapidly reduces electrical stability and oil wettability in OBM. Emulsion stability was increased as a precaution to the extremely fine particles created through salt re-crystallization which has detrimental effect on stability. Fresh water in the water phase helps to minimize salt saturation and crystallization.
This paper describes the drilling fluids challenges faced while drilling the Gotnia formation and the progress made over the years to drill this formation successfully.
Development of New Type Curves for Production Analysis in Naturally Fractured Shale Gas/Tight Gas Reservoirs
Authors: Xu Bingxiang , Li Xiangfang , Haghighi Manouchehr , Cooke Dennis , Zhang Lei 
Published: March 2015

Abstract
As a result of ultra-low rock permeability and hydraulic fracturing, both shale gas and tight gas exhibit long-term transient and linear flow behaviour. Previous studies have introduced type curves for linear flow and assumed that the production is dominant by the stimulated reservoir volume (SRV). The more recent type curves are developed to include the production contribution from un-stimulated region which has been assumed to be a homogeneous system. We know that some tight or shale gas reservoirs are naturally fractured and unstimulated zone is not homogeneous.
In current study, we have developed new analytical solutions (type curves) applicable for both natural fractured and hydraulic fractured shale gas/tight gas reservoirs in which both SRV and non SRV regions have double porosity flow behavior. Our developed type curves are more general and applicable for both homogenous and naturally fractured reservoirs.
Numerical models were used to validate the analytical solutions and obtained an excellent agreement. We have also developed new type curves for shale gas/tight gas evaluation. The flow regimes are identified to show linear flow and transition flow alternately, and are more complicated than the assumption of homogenous un-stimulated reservoir in late period. The parameters sensitivity of type curves was also investigated and analysed. It is shown that the reservoir size, interporosity coefficient and fracture permeability ratio have great influence on type curves while the effect of storativity ratio is not such significant because fracture porosity is very low compared to matrix porosity. We have compared the new type curves with the curves based on SRV and Brohi's solutions. It is concluded that double porosity behaviour of un-stimulated region has positive effect on production even if the fracture permeability is in the order of matrix permeability and the matrix bulk shape factor is low.
The Role of Underground Storage in Large Natural Gas Production Operation
Authors: Hoagie Merry , Amorer Gabriel , Wang Xiuli , Economides Michael J. 
Published: March 2015

Abstract
Underground natural gas storage has been used extensively in countries with large natural gas demand. Although much of the storage and withdrawal have been associated with seasonality, storage is becoming essential in an integrated natural gas management. It is particularly important in large operations, such as liquefied natural gas (LNG), where the total production rate must be maintained irrespective of the producing field day-to-day capacity.
Natural gas storage capacity is affected by reservoir volume and tolerable pressure (to avoid fracturing) and injection or production rates that are affected by reservoir permeability, natural reservoir drive mechanism, wellcompletion/stimulation, and the impact of cyclical losses.
We present here a new sequence of calculations and estimations demonstrating salient elements of this practice:•Maximum capacity estimation with a new type of graphical construction, blending concepts of the classical p/Z vs. cumulative recovery straight line in natural gas production.•Prediction of withdrawal rates and time, constrained by decreasing storage pressure.•Determination of maximum or sustainable withdrawal rate for a period of time. In all cases, the injecting and producing wells are hydraulically fractured. The hydraulic fractures are designed for the withdrawal rate. Thus, the required number of wells is determined.
These concepts are applied to a depleted natural gas field with an average pay of 33 ft and a permeability of 45 md. Forecasts of injection or production rates, cumulative storage or withdrawal, and pressure buildup or decline are presented as functions of time. The purpose of this case study is to sustain anLNG liquefaction operation for a specified period of time by employing under ground natural gas storage.