bluuebunny/crossref_metadata_2025_split huggingface dataset:
Global Field, Pilot and Laboratory Experience of EOR-WAG Flooding- Will it Make A Difference?
Authors: Ghedan Shawkat G. 
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
Primary and secondary drive oil production mechanisms are coming short in meeting the ever increasing global oil demand. Currently, many tertiary recovery-EOR projects are in the design or implementation stage in many parts of the world to help meeting the expected extra oil demand. The majority of these projects involve some kind of gas (CO2) injection. If injected below Minimum Miscibility Pressure, gas injection, however, suffers the problem of unfavorable mobility ratio which often reduces the chances of higher oil recovery in addition to adverse economic results due to gas recycling. To help match the technical results of these projects with their economic viability under the current oil prices, the industry should learn from the lessons of the available global experience of water alternating gas flooding to safeguard against un-optimized gas (CO2) injection projects. This should help to avoid unnecessary losses in time and money and to make the best incremental oil recovery possible. The results of large number of WAG flooding projects have been reported in the literature. Areas of application include the USA, North Sea, South East Asia, and Middle East. In this study, most if not all of the published literature on WAG process is reviewed and evaluated. Results related to the issues of screening studies, laboratory and modeling studies, and the evaluation of pilot and field applications are discussed and presented. Effort is made to show the pros and cons of the WAG process as opposed to only gas (CO2) injection. All these issues are presented in a comparative mode between the different global projects, resulting in best practices for studying WAG Flooding in the lab and via modeling, for pilot and field applications. Finally this paper makes recommendations for increasing oil recovery with less time and effort in the most economical fashion.
The Spirit of Socio-Economic Development
Authors: Al Hajji Sultan 
Published: May 2016

Abstract

Overview

The evolved frame of reference
The frame of reference for the energy companies has enlarged over a period with a change in the profile. The major change in profile emanates out of the philosophy to transform the commercial 'buyer-seller' or 'client-server' relations into socio-economic development as 'partners in inclusive growth'. Anthropology engineers coined a phrase Corporate Social Responsibility - CSR and made this an acceptable tool to gauge the performance of commercial establishments in their sphere of influence.

Definition of CSR
- CSR is a concept whereby companies integrate social and environmental concerns in their business operations and in their interaction with stakeholders on a voluntary basis. (source: CSR Europe) - Corporate Social Responsibility is the continuing commitment by business to behave ethically and contribute to economic development while improving the quality of life of the workforce and their families as well as of the local community and society at large. (source: The World Business Council for Sustainable Development in its publication "Making Good Business Sense" by Lord Holme and Richard Watts) - Corporate social responsibility is the commitment of businesses to contribute to sustainable economic development by working with employees, their families, the local community and society at large to improve their lives in ways that are good for business and for development. (Source: International Finance Corporation, Member of the World Bank Group.)
There could be different wordings of the definitions; however, the spirit is common - The Spirit of Socio-Economic Development.
We have heard of sceptical remarks like "the corporate social responsibility of a commercial organization is to make profit". Such remarks do have an element of truth. Commercial organizations need to make profit and invest a share of that profit in social responsibility projects and activities. The bottom line is not profit alone. We refer to Triple Bottom Line (3BL or TBL)
Definition of 3BL (or TBL) (source: Wikipedia)
In practical terms, triple bottom line accounting means expanding the traditional reporting framework to take into account ecological and social performance in addition to financial performance.
The three bottom lines are People (human capital), Planet (nature capital) and Profit.
Fault Detection Workflow In Al Khalij Field In Qatar
Authors: Klein Blandine , Gauthier Bertrand , Mccallum John , Emang Michael Ipui 
Published: May 2016

Abstract
In Al Khalij carbonate field, the impact of faulting and fracturing has long been considered insignificant on the dynamic reservoir behaviour. However with the continued field depletion, an interference between some wells has been noticed. This interference cannot be explained by matrix properties. Therefore, a better understanding of the detailed structure grain seems to be the key for understanding the field dynamic behaviour. This integrated study shows that faults can barely described from the seismic data. But it has been found that a detailed understanding of the field structure is possible if other data are also taken into account.
The model was therefore constraint with an integrated approach developed along the following four aspects:1. Structural interpretation of the horizontal wells;2. Seismic attribute analysis;3. Image log data analysis;4. Dynamic data analysis.
The structural interpretation of the seismic fault lineaments and the well fracture systems suggest that they are related to two successive compressive tectonic phases of different orientations which are controlled by a deep structural heritage and which result in a strike slip (transtensive), structural style.
A new structural model (Geo model) was created, but because of the insufficient reliability of the lower reservoir markers, a special attention was paid to the layer thickness construction. A meticulous structural study and the fault throw distribution analysis were performed before the final structural model construction to validate the structural consistency of the interpretation. All this work performed in 2D resulted in a very consistent structural network which was then used to define the 3D grid.
This geomodel reconciles all available data and analyses and gives a much more geological image of the field structure.- Layer thicknesses are homogenous and not affected by drastic changes close to well calibration points.- The resulting fault network appears to be rather predictive from recently drilled wells.
This new model will be the base of an updated reservoir model which should give a much better qualification of the field dynamic behaviour as investigated by other specialists.
Skin Calculation and Other Applications with New Sonic Measurement in the Gulf of Thailand
Authors: Jiang Long , Pabchanda Suwit 
Published: May 2016

Abstract
Since the first sonic logging tool used for the petroleum industry in 1950s, we have seen many generations of acoustic measurements. The hardware and software changes made over the decades focused mainly on the improvements of compressional and shear measurements which are one dimensional in the near-wellbore region. To understand the complicated reservoirs today, there is a need to look at the compressional and shear slowness in three dimensions.
The present wireline sonic logging tool that is equipped with a long receiver array and near and far monopole transmitters enables us to quantify the compressional slowness of near-wellbore damaged formation and the far-field undisturbed formation. This radial measurement adds an extra dimension to reservoir characterization.
The compressional radial profiling clearly shows the formation damage across part of the reservoir. By combining it with the pressure drawdown mobility taken from undamaged and damaged zones, one can, for the first time, measure the mechanical skin just after drilling. The information is available at the wellsite. It helps to optimize the real-time data acquisition and completion selection.
The fluid identification is one of the challenges in the deeply invaded reservoirs. The depth investigation of new sonic measurement is much deeper than conventional neutron density logs and previous sonic logs. Other applications including gas detection in deeply invaded reservoirs provided unique solutions in the Gulf of Thailand.
The field example also demonstrates an enhancement in vertical resolution with the multiple-shot processing technique. This is much needed for evaluating the thin reservoirs.

Introduction
Traditionally, the total skin is calculated by well tests. The limitation is that the well tests do not measure the individual skin parameters. The methods for calculating the skins are well documented in many papers. Pucknell and Clifford (1991) discussed various methods. However, there are many assumptions, including the radius and permeability of the damaged zone.
The mechanical skin caused by drilling and perforation is one of the most difficult skins to measure. While the modern perforation technique can reduce or eliminate the perforation skin, the drilling damage remains the same.
In this paper, a new method for evaluating the drilling damage is introduced. It uses the new sonic data which provide direct measures of the formation damage (or alteration) radius.

Methodology
The principles and applications of the new 3D sonic measurements are well documented in Pistre et al. (2005). Compressional radial variations are determined by evaluating both the short- and long-spacing monopole measurements. Short spacings probe the formation in the near field (shallow), whereas longer spacings probe the formation in the far field (deep). This is graphically represented in Fig. 1.
Developing New Petroleum Engineers in a Non-Operating Environment
Authors: Ibrahim Mohd Isa , Almuhanna Ali Ibrahim , Amiri-Garroussi Kourosh 
Published: May 2016

Abstract
The paper will briefly explain aspects of career development for a new young engineering graduate to become a petroleum engineer in an international subsidiary of a National Oil Company in a non-operating environment.
Developing a new graduate into a petroleum engineer is a challenging goal to achieve, especially in a non-operating company environment. The essential well-site and field operational knowledge/experience is hard to obtain. Therefore, a simple approach is adopted as an initial 2-year training stage in order to capture the basic petroleum engineering hands-on experience required for the young engineers that require continuous assistance.
The development scheme is adopted by the company to accelerate the placement of local graduates in various technical positions, in order to support senior petroleum engineers. It consists, among others, planned work programs, daily tasks, formal training courses locally and internationally, on-job-training, conduct ad hoc focused assignments and projects, getting exposure to operational sites and further study on part-time degree course.
The development scheme has yielded positive results. Many young engineering graduates have excelled in their careers to higher levels within a few years, however exception also exists.
The development scheme will continuously be improved to an in-depth focused development program that will capture more operational knowledge and experience. Hence, it will generate skilled and knowledgeable young professionals to operate and manage oil and gas companies.

Introduction
KUPFEC is one of the many subsidiaries of Kuwait Petroleum Corporation (KPC). There are four subsidiaries which are involved in upstream exploration and production of oil and gas - KUFPEC (Kuwait Foreign Petroleum Exploration Company) engages in international foreign onshore/offshore exploration & production, mainly as a non-operating Joint Venture Partner, while the other three engage in the domestic and nearby acreage exploration / development / production.
KUFPEC's global assets stretch from West Africa to Far-East and from Australia to the North Sea. KUFPEC's 2030 strategy consists of the following:• To achieve targets set by KPC for crude oil and gas production & reserves increases.• To give preference for investments which facilitate transfer of know-how.• To achieve & maintain optimal ratio of upstream oil and gas.• To become an operator of international upstream assets.
Application of Permanent Reservoir Monitoring Data (DTS* & PDG*) in a Mature Offshore Malaysian Oil Field, for Production Optimisation and Workover Control
Authors: Goh Kim Fah Gordon , Gee Michael Joseph , Zaini Muhamad Zaki , Molavi Saeed , Salim Muzahidin Muhamed 
Published: May 2016

Abstract
Permanent Downhole Reservoir Monitoring and Surveillance is becoming fundamental for optimal reservoir management, without the requirement to re-enter the well. In order to identify zonal allocation from multi layer reservoirs, DTS and zonal PDG data have been integrated to provide a cost effective alternative to conventional wireline logging (e.g. PLT), thereby mitigating oil deferment and intervention risks.
This paper demonstrates the approach taken by integrating DTS and PDG data with reservoir petrophysics, to interpret reservoir inflow performance, to maximize the benefits of a successful workover, by increasing oil production and decreasing water-cut. A field case from offshore East Malaysia will be shown, demonstrating the following benefits:1. Zonal inflow profiling and trending from DTS data interpretation2. The effective use of PDG data to calibrate DTS-derived flowing BHP during zonal flow profile interpretation, has improved interpretation accuracy3. Increased oil production from the workover with zonal SSD changes, using the interpretation results of integrating DTS and PDG data, in order to reduce surface water production.4. The value of permanent DTS during initial completion pressure testing, to identify leak paths along production tubing, thus saving rig time and remedial leak-detection intervention.5. The advantages of permanent downhole monitoring against alternative of conventional PLT intervention.
Throughout the DTS and PDGs deployment, the data acquired has been reliably used to assist future production strategy and reservoir management. The availability of zonal pressure and rate contributions derived from DTS and PDGs data, has allowed optimal reservoir layer drawdown, to mitigate the effects of potential sanding, which is the only well in the field that has been completed without the normal field practice of gravel pack.
The retrieval of fiber-optic temperature data and PDG pressure measurements is unlimited, enabling rapid production diagnostics without the need for production deferment. Hence, a cost-effective data acquisition over the well life is achievable which has improved the analysis of zonal comingled production in multi-layer reservoirs and guided the future zonal workover control.
Exposure to Phosphate-based Completion Brine Under HPHT Laboratory Conditions Causes Significant Gas Permeability Reduction in Sandstone Cores
Authors: Downs John David 
Published: May 2016

Abstract
High-density potassium phosphate and potassium/cesium formate brines were tested in an advanced core flood test rig for their compatibility with low-permeability sandstone containing simulated formation water under HPHT conditions. The tests were carried out at a temperature of 175oC (347 oF) and pore pressure of 5,800 psi. Compatibility was determined by comparing the relative gas permeability of the cores before and after exposure to the brines under HPHT conditions.
The 10–20mD sandstone core plugs, containing simulated North Sea HPHT gas reservoir water at residual water saturation, were flooded with 10 pore volumes of test brine and subsequently equilibrated with the brine for 48 hours to allow chemical interaction. Drawdown pressures of up to 100 psi were then created on the wellbore side of the core to create gas flow. Gas permeability was measured after flowing 4,000 ml (approx. 2,000 pore volumes) of humidified gas through the core. The results showed that flooding this core with the potassium phosphate brine reduced the gas permeability by more than 90%. By comparison, flooding with cesium formate brine created a modest improvement in the permeability of the core to gas.
Examination by SEM of the core damaged by the phosphate brine showed that its pores were partially obstructed with a thick layer of scale. The scale was particularly plentiful in areas of the core where illite clays were present. The scale was examined in situ by EDS and found to contain potassium and phosphorus. It is known that phosphates in aqueous solution are strongly adsorbed onto mineral surfaces where they can form precipitates and complex insoluble salts from exposure to multivalent cations. Aqueous phosphate solutions are also known to react with clays to form solid precipitates. It is possible that the scale formed in the core as a result of interactions under hydrothermal conditions between the invading phosphate brine and, inter alia, the pore-lining illite clay deposits naturally present within the rock.
The scale modeling software, DownHoleSAT, predicted a significant risk of various phosphate scales being formed as a result of mixing of the formation water and phosphate brine inside the core under the experimental conditions. Such scales may have contributed to the formation damage observed in the core flooded with the phosphate brine.
Implementation of Next Generation Intelligent Downhole Production Control in Multiple Dipping Sandstones Reservoirs, Offshore East Malaysia
Authors: Chen Jiun Horng Chris , Nuriyadi Mohd Azrul , Bakar Mohd Farris , Kamarul Zaman Nur Hazrina , Aminuddin M.K. M. , Mohd Yusoff Saiful Anuar , Goh Kim Fah Gordon , Gill Premjit Kaur , Luke Darren , Ahmad Eddep 
Published: May 2016

Abstract
The 'S' field, located offshore East Malaysia, consists of multiple-dipping heterogeneous sandstone reservoirs with unconsolidated formation. These multi-stacked reservoirs have an overall 40m thick oil column with marginal Oil-Initial-In- Place (OIIP). A large gas cap, i.e. twice the OIIP equivalent, also exists. Scenarios of zonal gas-out leaving huge oil bypass and moderate aquifer strength with inevitable water invasion cautioned the asset team to consider intelligent zonal flow control especially in its horizontal producing wells.
Two of the 14 horizontal producer wells in this marginal field have been screened to apply the modular integrated intelligent completions system (IICS) to actively control and permanently monitor zonal inflow for optimal production. Future selective production control and data surveillance enabled by the IICS are essential to fulfill the needs for delicate downhole zonal flow balance for ultimate oil incremental and recovery. It provides control against the aggressive gas cap expansion at the heels while addressing the moderate aquifer coning-up problems from the dipping toes as the field depletes.
This paper highlights the successful implementation of the next generation intelligent completions system in a complicated, highly-dipping, multi-layered sandstone reservoir with commingled production. In this multi-zonal production solution, the conventional surface-controllable downhole zonal flow control valves are now integrated with data surveillance gauges, intelligent sensors and isolation packers all into one single completion joint, instead of the precedent multi-joints system (i.e. splicing required up-to 3 joints per zone conventionally). This single modulated joint system has reduced installation time substantially in comparison to conventional intelligent completions installations. The risk of surface completions make-up damage before run-in-hole is also greatly reduced with less connecting components. This robust yet compact system has made on-site completions tally adjustment easier and is enabled with LWD data update while drilling. As a result, intelligent completions design becomes more flexible and responsive to actual reservoir challenges and drilling surprises - providing an all together "intelligent" solution.
This paper also discusses the screening process from simulation performed for candidate evaluation to the resulting impact on production post-installation. Future applicants of such technology with similar fields' nature and risks can benefit from the discussed lesson-learnt; best-practice workflow and seamless teamwork and coordination between the project team and service providers in delivering an advanced fit-for-purpose solution.
Evaluation of Time-Domain Controlled-Source Electromagnetic Method for Detecting Hydrocarbon Targets in East Malaysia Environment
Authors: Fuad M. Izzuljad Ahmad , Bujang Awg Amirul Zakry Awg , Majid Hani Noorashiqin A. , Rahim M. Faizal Abd , Meju Maxwell Azuka , Arshin Boshara Merghani 
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
The time-domain Controlled Source Electromagnetic (tCSEM) method is emerging as a practical tool for oil and gas exploration on land and shallow marine environments (Wright et al., 2002; Ziolkowski et al., 2007). In particular, it can overcome the airwave interference problem faced by frequency-domain CSEM method in shallow water (Weiss, 2007). We have used a 1D broadband tCSEM inversion technique developed in-house. The forward problem is solved using the algorithm of Edwards (1997) while the inverse problem is solved using a variety of nonlinear parameter estimation methods (Meju, 1992, 1994). The inversion method generates either blocky sharp-boundary model or the smoothest model that fits the data recorded for different offsets and various transient times. In this work, a layered-earth resistivity model was constructed using the local borehole resistivity log and served as the test model (ground-truth). The parameters of this model were systematically varied and used to generate forward model responses enabling us to determine the effect of target depth, thickness and resistivity variations. The synthetic data for the ground-truth model were finally inverted to test the detection capability of tCSEM.
The aim of our research was to evaluate the applicability of tCSEM technology in East Malaysia environment by studying the effect of target and water depth, target thickness, target resistivity variation, and target detection limits using a combined numerical modelling and inversion approach.
The results of modeling and inversion studies suggest that the tCSEM method is capable of detecting hydrocarbon reservoirs in East Malaysia environment. The inversion responses become more significant when dealing with thick, strong resistivity, and shallow marine hydrocarbon target. From the case of target depth variation, the inversion responses capable to distinguish hydrocarbon target at difference depth.
From this study, we capable to investigate in detail about the strength and limitation of this method in East Malaysia environment and this beneficial information can become a guideline for future feasibility study and tCSEM survey planning. Furthermore, this method also can be used as an alternative method to provide technical solution and reduce exploration risk especially in shallow marine environment.