bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimum Development on Low Permeability Reservoir - New Phase Opportunity for Mature Badak Field
Authors: Hermawaty Irma , Permana Robhy , Silitonga Frans , Wijanarko Andre , Soenoro Amireno 
Published: May 2016

Abstract
VICO Indonesia is the operator of Sanga Sanga Production Sharing Contract (PSC) area in the onshore Mahakam Delta, East Kalimantan, Indonesia since 1968. Over 40 years, the PSC has produced more than 12 TSCF of gas through more than 800 wells to feed the Bontang LNG Plant and domestic market. One of the major fields in the contract area is the Badak Field, which has contributed more than 6 TSCF of gas production.
Badak Field's reservoirs are the analog of the present day's Mahakam delta, and comprise of stacked distributary channel sands deposited in the deltaic environment draping on a four-way dip closure anticline. The shallower stratigraphic interval is dominated by fair to good quality upper delta plain, amalgamated channel sands, with a combination of water and depletion drive mechanism. The deeper stratigraphic intervals are dominated by fair to poor quality lower delta plain, more isolated distributary channel sands and mouth bar. The main reservoir drive mechanism is depletion drive.
As the early development strategy of the Badak Field had been focused mainly on drilling the best reservoirs, those shallow reservoirs in the crestal area, the majority of these reservoirs are now depleted. In contrast, low permeability deeper reservoirs with relatively higher reservoir pressure, still contain significant remaining resources. VICO's depletion challenge is to balance between increasing the recovery from the deeper intervals, whilst continue optimizing the recovery from shallow intervals.
An Integrated subsurface study has been conducted to understand the geological description of the reservoirs, ultimately to unlock the reserves of the deeper low permeability intervals. Several development options have been carefully evaluated, which lead to the implementation of new technologies to optimize recovery, including cluster wells, horizontal wells, and hydraulic fracturing. The results of the implementation of the development strategy and technology have been outstanding. This has helped sustain the Badak Field's decline rate at around 25% annually compared to a 45% natural decline. In 2011, the gas production was successfully maintained at 75 MMSCFD or 3 times the base line of the "do nothing" case prediction, with more than 55 BSCF of reserves progressed.
Assimilating Microseismic and Welltest Data Using EnKF for Accurate Reservoir Characterisation
Authors: Han Mei , Li Gaoming , Chen Jingyi 
Published: May 2016

Abstract
The pressure trainsient data in welltest can only resolve the thickness-weighted average permeability but are more sensitive to the high productive (high permeability) layers. The mircroseismic data between fracture simulation treatment well and the monitor wells can only resolve the average velocity along its wave path but are more sensitive to the layer (or region) with high wave velocity (low productivity). Therefore, these two types of data are complimentary to each other in reservoir characterization. In this paper, we assimilate these two types of data using the state-of-the-art ensemble Kalman filter (EnKF) method. Layered homogeneous and heterogeneous reservoir examples verified the complimentary nature of these two types of data. The porosities and permeabilities in the layered reservoir obtained after assimilating both types of data are comparable to assimilating pressure trainsient and layer rate data. As EnKF is a stochastic process, we generated 10 different ensembles for each example for better uncertainty quantification. Assimilating only one type of data may yield biased estimates in porosity and log-permeability and hence biased prediction in the layer rates, while assimilating both pressure and microseismic data yield good estimates in reservoir properties with smaller uncertainty bound and hence more accurate layer rate prediction.
Innovative Method for Exploring Potential Reservoirs in Areas with Limited Data - Case Study from Deepwater South China Sea
Authors: Mukherjee Anubrati , Jiao He , Fang Yin Cheng , Wu Pei Shu , Hinz Curtis , Bo Zhang Zhen 
Published: May 2016

Abstract
The study area is in deep water offshore South China. Only one well has been drilled so far. There are 2 target intervals. The shallow interval encountered gas bearing sands with low porosity (average 5%) and high volume of clay (average 55%) and the deep interval carbonates and volcanics with no sand. Gas found in shallow interval was not of commercial saturation. Two key issues needed to be resolved from this study: a) Are there better quality sands away from the drilled well within the seismic block in the shallow interval? b) Are there sands in the deeper target interval? If so how are the qualities of the sands? The study looked at ways of using recent advances in seismic inversion and rock physics unravel most information from seismic in absence of sufficient hard data.
A Journey Towards Operational Excellence - from Effective Plant Performance Monitoring to Capturing Opportunities
Authors: Amminudin Kamarul A. , AbdulMohsin Mohammed T. , Muaibed Mohammad F. 
Published: May 2016

Abstract
Since being commissioned in June 2009 and being the largest crude increment program undertaken in recent history, Saudi Aramco's Khurais Central Processing Facility (KhCPF) has positioned itself for a greater leap by embarking on various operational excellence initiatives. This includes various optimization initiatives ranging from maximizing crude yield to optimizing energy efficiency performance. Nonetheless, to ensure a sustainable optimum performance following the implementation of these initiatives, which proves to be the greatest challenge for the facility, an in-house engineering dashboard was created to provide engineers and operations with plant performance monitoring capabilities.
To reinforce this drive for operational excellence, a multidisciplinary team member task force was formed with the objective of realizing the opportunities identified during the process improvement. The focus of the task force is to capture "low hanging fruit" opportunities that can be implemented immediately and require little or no cost. Today, after implementing these initiatives, the KhCPF is realizing the benefits of the operational excellence initiatives in the most sustainable way and has achieved significant improvement in the plant energy performance index by 3% and enhanced its crude recovery by around 0.2% without incurring any capital cost. Such value creation initiatives do not stop the task force from setting out on a journey of continuous improvement as part of its ongoing operational excellence effort.

Introduction
Saudi Aramco successfully commissioned the KhCPF in June 2009 as being the world largest crude increment program in history. This mega facility is located approximately between Riyadh and Dammam expressway in Saudi Arabia (Figure 1). Its facilities are intended to produce oil at 1.2 million barrels per day together with associated gas and condensate from three major fields in the area; namely, Khurais, Abu Jiffan and Mazalij. It also has the facility to cater for the water injection requirement for these fields, which is being supplied from the seawater treatment plant.
Sand Detection Using Integrated AVA and Rock Property Analysis: Applications in Horizontal Well Drilling
Authors: Romli Gunawan 
Published: May 2016

Abstract
An integrated methodology to characterize sandstone reservoirs in offshore Arabian Gulf oil fields is described in this paper. The methodology incorporates amplitude vs. angle (AVA) inversion and rock property analyses with the objective of defining optimum elastic properties to separate sandstone from shale and limestone. A set of elastic property cutoffs is determined from the rock property analysis and used to interrogate the AVA volumes to detect sandstone reservoirs and map their lateral and vertical distributions. The detected AVA sand images have been used to support planning and drilling of more than 100 wells in the last five years. Several examples from recent drilling results will be shared to show the application and limitation of the technique as well as recommendations for future improvements.

Introduction
Offshore Arabian Gulf oil fields make a significant contribution to overall Saudi Arabian oil production. Three major offshore oil fields produce from the mid-Cretaceous Wasia Formation. Figure 1 shows the stratigraphic column and type logs of the Wasia Formation. The Safaniya and Khafji Members of the Wasia Formation are the main oil reservoirs. They were deposited in a fluvio deltaic environment and consist of multiple sandstone and shale sequences with a few thin limestone beds. The sandstone facies range from shaly to very clean sands, with thicknesses ranging from 5 ft to 150 ft and an average porosity of about 20%.
Integration of Multi Functional Disciplines to Optimally Develop a Greenfield Gas Development Project: Example from T Field, Malaysia
Authors: Sunhaji Iman , Gorden William C. , Khalid Khadijah , Liew Alex , Jaynes Scott 
Published: May 2016

Abstract
A multidisciplinary teamwork approach has been taken to plan the development and execution of a greenfield gas project offshore Peninsular Malaysia. Domestic demand for gas in Peninsular Malaysia remains strong mainly to fuel growing electricity demand. Timely execution of the T Gas Development project is critical to supplementing declining capacity from existing developed fields and ensuring the ability to meet gas supply obligations.
The T field is a faulted, compressional anticline comprised of lower to middle Miocene sandstone reservoirs. The major reservoir in T consists of shallow, fluvio-deltaic to near-shore marine sediments containing a dry, non-associated gas. Discrete channel meanders and faulted segments within the field contribute to uncertainties in reservoir connectivity and compartmentalization. Incorporation of conventional seismic volumes with a derivative sand/shale indicator volume, and combined with an understanding of the environment of deposition and seismic stacking geometries, were used to better capture the range of predictive uncertainty in the lateral and vertical heterogeneities observed in the seismic data.
Installation of down-hole pressure gauges in the production wells are expected to increase understanding of dynamic reservoir connectivity during production. Due to shallow reservoir burial depth, the development wells were designed with ERD (extended reach drilling) ratios of up to 2.9 in order to optimize well placement and reserves capture. Furthermore, installation of downhole sand control in these high-angle wells will be challenging, but is critical to ensure production sustainability and minimize future wellbore interventions. Alternate Path Technology (APT) screens will be utilized to ensure successful frac pack completions at high well angles.
The T Field project utilizes the 'Design One, Build Multiple' concept via replication of proven design components to optimize cost and schedule. This paper describes key challenges for T Field development planning, including managing reservoir compartmentalization and connectivity uncertainties, optimizing well design, and the use of 7" tubing completions in high quality sands to maximize well deliverability and meet gas supply requirements with optimum well count for reserves capture.
Early stakeholder-alignment and detailed execution planning have been pursued to meet aggressive project schedule reflecting the need to rig-up before monsoon season and to tie into a major gas compression hub during a limited shut-down window.
Rock Typing for a Fractured Carbonate Reservoir with Low Resistivity in Middle East
Authors: Mu H. , Sun X. , Lin S. , Feng Z. , Xu F. 
Published: May 2016

Abstract
The T reservoir is a fractured carbonate reservoir located in Middle East with low resistivity and high total porosity. Fractures of various scales and dip-azimuth are well developed. The storage space for matrix consists of intragranular pores and micro fractures. Effective porosity interpretation suggests that less than 20 percent porous volume in total porosity is effective. FMI log interpretation of more than 120 wells show that fractures are well developed with various apertures, dip and strikes.
Three types of the reservoir rock were distinguished according to the combination of range of effective porosity and scale of fractures. Rock Type 1 is the fractured limestone in lower part of reservoir characterized by development of large scale fractures. The effective porosity is less than 5% with total porosity over 20%. Rock Type 2 is the fracture-matrix mixed limestone in middle part of reservoir characterized by smaller scale fractures and pores connected to fractures. Rock Type 3 is the matrix limestone in upper part of reservoir with higher effective porosity (over 20%). Dynamic data show that the major productivity is contributed by Rock Type 1 and Rock Type 2, which are distributed in lower and middle intervals of T reservoir.

Introduction
Reservoir rock typing is one of the most challenging subjects in carbonate reservoirs. Definition of significant reservoir rock types petrophysically and geologically is critical in the reservoir characterization, which is also fundamental in providing a link to geological modeling. If the reservoir rocks are properly classified and defined, the real dynamic characteristics of the reservoir will be provided in reservoir simulation modeling.
Ocean Bottom Node Seismic at the Deepwater Bonga Field, Nigeria
Authors: Quadt Edwin , Detomo Rocco , Pirmez Carlos , Mbah Reginald , Milcik Paul , Olotu Samuel , Emakpor Jake 
Published: May 2016

Abstract
The Bonga Main field, Nigeria's first deepwater discovery, was discovered by Shell Nigeria Exploration and Production Company (SNEPCo) in 1995 and is located approximately 120 km offshore at water depths of 800–1200m. First oil production started in November 2005, and Bonga has an average production capacity of 200,000 barrels/day. Oil production is from 4 main stacked turbidite reservoirs (690, 702, 710/740 and 803) using pressure maintenance via water injection through producer & injector well pairs. The Bonga Main field is covered by an initial 1993 3D seismic streamer dataset and a block-wide exploration 2000 3D baseline seismic streamer survey.
To monitor changes in reservoir dynamics since start of production in Q4 2005, a 4D seismic monitor streamer survey was acquired in Q1 2008. The Bonga 4D acquisition was completed on time, within budget, and with excellent HSE performance : the data quality was excellent (NRMS ~ 12.5%) where the (2000) baseline survey could be well repeated, but was of much poorer quality in the close vicinity to the field's surface obstructions (Floating Production, Storage and Off-loading vessel - FPSO and Surface Production Manifold - SPM). The 4D results of this survey added significant value to the development of the asset by improving the understanding of reservoir connectivity and the sweep efficiency between injector and producer wells, making the project a clear technical and business success. Figure 1 shows the amplitude maps of the 702 reservoir for the 2000 baseline, 2008 monitor, and the 4D difference. The bright colors indicate the presence of oil, with the 4D difference map clearly showing where water has replaced oil.
New 10 3/4 HPHT Casing Valve Successfully Applied in Deep Well Sour Environment
Authors: Ferrara Paolo , Molaschi Claudio , Menard Bill , Rinaldi Francesca 
Published: May 2016

Abstract
In recent years, drilling operations are facing increasing challenges. Deepwater and ultra-deepwater environments, HPHT applications, anomalous pressure regimes and reduced margins between pore and fracture gradients are setting new critical thresholds to the ability of reaching new hydrocarbon reserves and are raising new operation safety issues for business sustainability.
In this framework, best practices and a series of dedicated tools have been developed throughout the years. Nowadays, the best oil industry practice to cope with these problems is represented by Managed Pressure Drilling Systems (MPDS), consisting of surface tools and equipment that enhance drilling capabilities and grant a safe drilling process.
To complement MPDS, the possibility to introduce new safety barriers directly into the well has also been considered. Among these barriers a new casing valve, with surface control lines, rated for HPHT and sour environments has been developed.
As known, casing valves are integrated into casing string and isolate the open hole when no drill string is present below the last casing point. Casing valves are thus directly reducing the risk associated with tripping in and out of the hole and, in specific cases, can lead to considerable cost savings avoiding the necessity of mud cap barriers to restore trip margin whenever necessary. In addition, associated to MPDS, casing valves represent a testable barrier for isolating the open hole when a double independent barrier is required to safely continue operations such as in BHA tripping, liner running etc.
This paper describes the first worldwide application in deep well sour environment of a 10 ¾ casing valve that was set in operations in 2011. In the paper both qualification process and installation experiences are described and reported.
Design Optimisation of Hydraulic Fracturing for Oligocene Reservoir in Offshore Vietnam
Authors: Nguyen Danh Huu , Bae Wisup 
Published: May 2016

Abstract
Many fields in offshore Vietnam with high production have been operating for a long time; however their production has been declining in the past few years. The most challenging problem is dealing with the heterogeneous structures such as Oligocene reservoir with a porosity range from 12% - 16% and a permeability of 0.1mD - 2mD. Therefore, natural flow of oil from these reservoir into the wellbore is retarded. Need for increasing production, a good understanding of reservoir characteristics, and designing a hydraulic fracturing treatment in Oligocene reservoir to maximize oil recovery is necessary.
The key factor for this success is optimum treatment design. This paper shows an integrated approach using technical and economic optimization of hydraulic fracturing design, as well as describing the recommended procedures coupled with field-case study and actual results. We optimize fracture treatment based on economic indicators not only Net Present Value (NPV), but also Discounted Return on Investment (DROI), and nodal analysis is used to help determine optimal fracture-length based on productivity potential. The hydraulic fracturing simulator M-Frac is used for accounting this design.
Based on these concepts, the results of the optimum treatment design present that a fracture half-length between 90 and 200m is required to maximize NPV and the initial fracture design is scheduled for 150,000 lbs of intermediate strength proppant to create a fracture half-length of approximately 100m. The success of this study in estimating production capabilities is a valuable lesson for future application in Cuu Long basin, offshore Vietnam.
Near Balance Drilling: Enhanced Safety and Real Time Control in Deepwater
Authors: Capurso Pietro , Spada D. , Besenzoni L. , Tufo M. , Copercini P. 
Published: May 2016

Abstract
Scope of the work is to describe the Near Balance Drilling (NBD) technology and the benefits it can bring to drilling operations in challenging environments. NBD is an advanced drilling technique developed to increase safety in drilling operations and allow drilling through formations with narrow margin between pore gradient and fracture gradient. The technology has been developed to be applied in all critical onshore and offshore wells and has recently been implemented on a deepwater High Pressure well drilled with a semi-submersible rig, with very positive results. Introduction Most interesting drilling prospects nowadays present extremely narrow operative margins between formation's pore gradient and fracture gradient. This strong criticality is even more challenging in exploratory wells, where the above mentioned margins can be quite unpredictable. Finding a way to exploit such reservoirs with conventional drilling methods has often proved to be ineffective, if not even impossible.
Drilling with reduced operative margin require an accurate control of all drilling parameters in real time, especially of the Equivalent Circulating Density (ECD) obtained at the bottom hole while circulating. Whenever the operating window above pore gradient is limited, the risk of fracturing the formation is very high, with consequent mud losses. On the other hand, keeping the ECD below the fracture gradient could bring the mud weight to be lower than the pore gradient in static conditions, as soon as mud pumps are stopped (i.e. during pipe connections), leading to a high potential risk of influx from the formation into the wellbore.
The Development of a New Methodology to Reduce Uncertainty in Implementing a New EOR Project
Authors: Perez Rodriguez Sergio , Soto B. Rodolfo , Soto David 
Published: May 2016

Abstract
A methodology for risk analysis of EOR projects is developed based on giving to their three standard phases elements from integrated reservoir management and from the methodology of scientific research. Phase 1 starts with the systematic analysis of the variety of factors categorized by its financial side, probabilistic entity features and whether or not they correspond to the petroleum engineering system. For all variables, a key point in Phase 2 is the full examination of their modalities of relationship with a contingency table. They are introduced as controls of the mathematical model, beyond the scope of plain correlations. To decrease uncertainty for a given variable displaying distributions with a similar goodness of fit, is selected the one with the least Coefficient of Variation. For time dependent variables is best the selection of two-dimensional distributions instead of one-dimensional ones, as shown by results of applying the criteria to evaluate information. Although the method guidelines are of general application for the risk analysis, the nature of each EOR project involves particular aspects to consider under their own terms. A chemical type of EOR project at the BCF illustrates the general methodology proposed.
Successful Use of Fundamental Reservoir Management to Flatten the Oil Production Decline in a Mature Field in the Gulf of Thailand
Authors: Tantrakul Pongpob , Pritchett James 
Published: May 2016

Abstract
The Platong field is a mature field situated in the northern section of the Pattani basin which is composed of both oil and gas reservoirs. A major characteristic of this field are small faulted, compartmentalized fluvial reservoirs with depletion drive as the main drive mechanism. With small reservoirs and an absence of aquifer support, recovery from primary oil production is low. Commingling production from multiple reservoirs is required to improve production rate and develop each reservoir at a lower cost. Aggressive infill programs are required to offset sharp production decline unless secondary recovery methods can be utilized to boost production.
In 2011, the field marked another major accomplishment in reservoir management (RM.) During the year, the base layer oil decline rate was flattened from the preceding 5 year range of 27% to 42% average annual decline rate per year to less than 15%, Figure 1. This significant improvement in the production performance resulted from proactively implementing strong RM fundamentals through cross-functional teams and delivering on waterflood and gas lift projects.