bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Potential of Compressed Natural Gas Transport in Asia
Authors: Wang Xiuli , Marongiu Porcu Matteo 
Published: November 2008

Abstract
Natural gas use is expected to increase dramatically in the world over the next two decades, especially in the two fastest growing countries in Asia: China and India. Japan is already greatly dependent on natural gas. In connecting sources with markets, natural gas is transported with two well-established technologies: 70 percent by pipeline and 30 percent by liquefied natural gas (LNG). Pipelines traversing land masses, when feasible, are the obvious option. However, offshore pipelines have a distance limit and a terrain restriction. LNG facilities (both the liquefaction process at the source and the re-gasification process at the receiving end) are expensive to construct and the entire process is complicated, costly, and energy wasteful. It is applicable for long haul sea distances and large volumes of gas.
Waterways-going compressed natural gas (CNG) is an alternative that many people have proposed in recent years but has not made a substantial head start for two reasons. First, the emphasis for investments worldwide has been primarily on LNG and, second, CNG vessel designs and projects have been envisioned to eke a bite out of the LNG pie, which is not necessarily a good approach.
CNG must make a substantial impact in shorter distances and smaller offshore markets which are not connected to large pipelines or baseload LNG accepting facilities. We show that for shorter distances (e.g., 1,000 km or 600 miles) LNG simply cannot compete with CNG. Even at longer distances (e.g., 2,000 km or 1,200 miles) CNG is still more attractive, assuming that offshore pipelines are not feasible. For smaller volumes, such as 1 to 2 Bcm/yr (35 to 70 Bcf/yr) CNG is the only solution to bring this energy source to many markets.
We scope Asian potential for CNG by connecting suitable source and market candidates. In this paper, a particular feasibility study of CNG transport in domestic Indonesia is performed. Results show that CNG is an excellent solution to transport Indonesian natural gas from fields such as Arun, Bontang, and Tangguh to domestic customers in the areas of Jakarta and Bali, especially from smaller reservoirs not currently considered as attractive for LNG. On the other hand, it does make sense to export LNG from Brunei, Malaysia, and Indonesiato Japan, South Korea, and China.

Introduction
A significant portion of natural gas reserves worldwide is located relatively near population centers across bodies of water. In many cases, traditional natural gas transport methods such as pipelines or liquefied natural gas (LNG) are not feasible or are too expensive. A new application of an existing technology, CNG, provides a solution for shipping natural gas across water.
Paraffin Inhibitor Applications in Deepwater Offshore Developments
Authors: Jennings David Wayne , Newberry Michael Edward 
Published: November 2008

Abstract
Paraffin inhibitors can have a significant impact on crude oil production for some developments. Paraffin inhibitors are used for reducing wax deposition in flowlines and/or for improving the flow properties of waxy crude oils. The effectiveness of the paraffin treatment is dependent on the crude oil chemical composition, inhibitor chemistry, inhibitor dose rate, and the production conditions. The available choices of paraffin inhibitor formulations for a particular application are, however, often fixed by constraints related to delivery or injection of the product. For example, products for deepwater subsea umbilical injection must remain fluid and solids-free at all conditions of temperatures and pressures the products experience in their respective injection paths - from the storage tanks all the way through the umbilical and (if present) capillary injection lines.
This paper details the challenges associated with the delivery of paraffin inhibitor chemicals for deepwater offshore developments. The stability of paraffin inhibitor formulations depends on both pressure and temperature. Umbilical and capillary line failure is a major concern in the oil industry. Best practices to qualify products for umbilical and capillary injection have been rapidly evolving over the last 10 years. Recently high-pressure viscometry has been found to be beneficial for product qualification. In particular, high pressure viscosity measurements have proven to be invaluable for determining whether pressure related stability concerns may exist in formulations at cold deepwater temperatures. Instability in the polymer solution phase behavior of paraffin inhibitor formulations at high pressures and cold temperatures may be the reason behind some industry umbilical line failures.
Also discussed are contrasts between deepwater applications in subsea umbilical lines and in DVA dry-tree capillary lines as the constraints on the paraffin inhibitor can be very different.
Four recent case histories of different types of deepwater paraffin inhibitor applications are presented: two subsea umbilical applications, one DVA capillary application, and one application for a well test. The case histories discuss how the paraffin inhibitor applications fit into the overall wax strategy for the projects, constraints placed on the products by the injection conditions, and performance of the products.
Recent CSEM Learnings in Deepwater Borneo
Authors: Choo Matthew , Young Chester , Ling Chin Tiong , Beer James , Shiner Peter 
Published: November 2008

Abstract
Controlled Source Electromagnetic (CSEM) is an emerging technology with the potential to provide detailed resistivity images of the subsurface. Following a string of successes with the deployment of CSEM and drilling performance in DW Borneo in 2004, CSEM data was acquired over a number of similar structures in 2006. Proprietary inversion techniques indicated the possible presence of a shallow surface resistive body, while hinting at the presence of slightly elevated resistivities at depth. An exploration well campaign was carried out over the prospect late in 2006, but rather than encountering the expected hydrocarbon pay, the well encountered a near surface and resistive hydrate layer. Good quality but water-bearing reservoir was encountered at the target depth. This disappointment was the first CSEM negative test in the basin and vindicates the need for further development of processing and interpretation methodologies. This paper will present the key CSEM experiences in DW Borneo to date, highlighting on the pros and cons of a still promising and evolving technology in what is still a challenging area.
Bubut - A Near Field Exploration Success, Inboard Brunei
Authors: Ahmad Zulkifli , Hassan Erma-Suryani , Raghavan Krishnan , Donaldson Ian , Kooper Hans , Maier Gijs , Dean Michael , Tucker Charles Frederick , Glover Stephen 
Published: November 2008

Abstract
Brunei Shell Petroleum (BSP) recently discovered Bubut (BU), a significant gas accumulation in its mature heartland and close to liquefied natural gas (LNG) facilities. The current commercial focus on gas raised the significance of the deep gas-bearing sequence which was first identified in 1983. It took another 20+ years before the full potential of the Upper Miocene (TB3.1-TB3.3) sequence in this area became apparent as part of the evaluation of the deep high-pressure (HHP) play. Well Bubut-2 (BU-2) subsequently (re-)discovered significant gas volume in the deep stacked pay sequence. The gas discovery forms part of a phased Bubut-Danau development with FID planned for 2011.
BSP's successful implementation of Techlog module K-MOD to model poor-quality and missing log intervals in well BU-1 and the "Back-to-Basics" way of working, resulted in an exploration success story in Brunei. Well BU-2 was drilled mid-late 2007 principally to test the deeper and highly overpressured distal topset play in Bubut, and also to re-assess the hydrocarbon presence and reservoir quality of the sequence already penetrated by BU-1.
The Bubut prospect is a simple 3-way fault/dip closed structure with the prospective reservoir section consisting of multiple stacked reservoir-seal pairs. BU-2 is a vertical well located 7 km offshore in a water depth of 17.4 m (Fig. i). The well targeted three objective intervals (Fig. ii):- the highly overpressured (&gt;18kPa/m) Deep B sands below 3450m ss,- the normal pressured Intermediate A sequence (~2600 - 3400m ss), and- the shallow L80 reservoirs (~1650m ss).
The reservoir architecture is made up of thin interbedded sandstones and shales of inner neritic origin and outer shelfal facies (latter mostly in the Deep B sequence). The reservoir sands are expected to have a large lateral extent.
BU-2 encountered gas in all three objectives and a total of some 190m net pay was logged (Fig. iii). Reservoir quality is best in the L80 with excellent porosities of 20–26%. Volumetric reward, however, is only modest due to the limited vertical relief at this level. The Intermediate A interval, estimated to contain about 90% of the total volumes, has relatively low average porosities of only 5 to 10%. Nevertheless, the NMR signature, as well as the RCI pressures and the successful recovery of 3 gas samples, all indicate the likely mobility of gas. Logging results from the highly overpressured Deep B sands indicate poor reservoir development with low (&lt; 5%) porosities and (residual?) saturations.
The Challenges and Advantages of Openhole Completions in the Manati Gas Field
Authors: Calderon Agostinho , Aragao Atila Fernando Lima , Chagas Carlos Magno , Guimaraes De Carvalho Cesar Roberto , Barbedo Renato Pimentel 
Published: November 2008

Abstract
The offshore northeast Brazil Manati field is located in the Camamu Bay with water depths less than 50 m. The sandstone gas reservoirs in this field have net pays with a thickness greater than 300 m and an average true vertical depth (TVD) of 1,400 m.
The original development project for this field did not include sand control for the initially forecasted production rates. However, the possibility of expanding the gas production rates of each well to more than 1 MMm3/D increased the associated sand production risk and led to the need for evaluating the best sand-control solution while considering the cost/benefit ratio.
This paper explains why an openhole gravel-pack completion was the best option in spite of some challenges such as large vertical net pays and high hydrostatic pressures of the sodium formate-based reservoir, drill-in fluid, and the sodium-potassium formate completion brine.
Compared with other alternatives such as cased hole gravel-pack or frac-pack completions, the openhole gravel-pack option has several advantages such as eliminating the need to run a liner, which requires good cementing isolation at the top; eliminating the cost of perforating long intervals; reducing the number of operations; and saving more than 10 days of rig time.

Introduction
The Manati field is located in the southern portion of the Bahia state and approximately 10 km offshore, where water depth varies from 35 to 50 m.. This area is extremely environmental sensitive (Fig. 1)
The field was discovered in 2000, through a prospect based on the seismic interpretation The reservoir is constituted by the tabular fluvial sands of the Sergi Formation, caped by the shales of ItaÍpe Formation and sealed laterally at north and east by the shales of Morro do Barro Formation, which were deposited in the space created by the erosive unconformity of the Tinharé Canyon, of Rio da Serra age. At east and south, the Mutá fault (north-south) and yet another northeast-southwest fault seal the accumulation through the contact with the same shales of Morro do Barro Formation (Filho, 2005).
During the drilling of a pilot well, a 187-m free-gas reservoir was initially identified. Perforating other exploratory wells showed a gas/water contact at 1,570 m vertical depth and net pay from 230 to 370 m in a reservoir with very good petrophysics proprieties. The evaluation of those data increased the initial reserves forecast for the Manati field, making it the largest gas reservoir in the north-northeast Brazilian region.
Understanding the Plumbing in your Field - Application of Reservoir Connectivity Analysis to Improve Oil and Gas Recovery
Authors: Tioe Eric , Elias Mohd Rohani , Sarif Mohd Rizam , Vrolijk Peter 
Published: November 2008

Abstract
This paper describes the application, outcome and benefits of Reservoir Connectivity Analysis (RCA) in three producing fields within the ExxonMobil Exploration and Production Malaysia Inc. (EMEPMI) operated area in the Malay Basin. The reservoirs within these fields typically have complex structural and stratigraphic relationships resulting in intricate reservoir plumbing that eventually influences the distribution of reservoir fluids and pressures. The RCA technique has been useful to help explain the plumbing resulting in scenarios that can yield drilling opportunities as well as in the placement and risking of drillwells. In addition, the technique also contributes to partially arresting the declining production trend and more importantly improves hydrocarbon recovery.
RCA is a work process that involves integration of diverse geologic and engineering data within a logical and rigorous framework to help predict formation fluid types, contacts and pressures in untested reservoir compartments. RCA provides a method for combining complex stratigraphic and structural models with fluid and pressure observations to define reservoir compartments and connections. Elsewhere within ExxonMobil, the approach serves as a technical basis for the understanding of geologic controls on known oil and gas distributions and contacts and their subsequent prediction. An important product of RCA is a series of consistent and permissible scenarios of non-unique field plumbing models.
In recent EMEPMI drilling programs, RCA results have been used to form the technical basis to identify additional drainage points and placement of drillwells, particularly in areas with limited well control, thus optimizing the field development plan. In the area of reservoir management, RCA provides a mechanism for rationalizing historical production behavior in mature reservoirs. The technique allows EMEPMI geoscientists to better understand and help explain the underlying technical reasons behind some of the anomalous production behavior as well as drillwell results. Results of the analyses also have been used as justification for improved/enhanced oil recovery plans that ultimately lead to the capture of additional reserves.
Despite its demanding and challenging work-flow, the benefits of RCA far outweigh the effort. The result is demonstrated in the three fields that went through a complete cycle of field-study, implementation of study results in drilling programs, and post-drill retrospective.
Integrated Genetic Analysis of Sediment Generation and Evolution to Predict Basin-Scale Clastic Reservoir/Seal Distribution and Character
Authors: Heins Bill , O&apos;Grady Damian , Ardic Can 
Published: November 2008

Abstract
Description: Genetic history ultimately determines the geographic and stratigraphic distribution of clastic reservoirs, clastics seals, and their quality. A thorough accounting of sediments' life history, including sediment generation (where, from what kind of provenance lithotypes, under what environmental conditions), sediment transport (topographic gradients, transport mechanisms), and sediment deposition (basin bathymetry, depositional mechanisms), can delineate the most likely distribution and character of clastic sediments in the basin. ExxonMobil integrates formal workflows, extensive global databases, and patented software to ensure that appropriate genetic information is consistently incorporated during exploration to guide reservoir/seal play-element interpretation and risking.
Application: We have used this approach to identify plays and reduce exploration risk in basins where reservoir/seal distribution and quality are not well documented because the basin is remote or the interval is difficult to image or drill.
Results, Observations, Conclusions: Observations in modern environments, where genetic conditions are known, and drilling results in ancient environments, where genetic conditions have been reconstructed, verify that this analytic process successfully predicts the distribution of sediment character.
Significance: Remote basins or basin intervals that are difficult to image or drill have the least existing exploration information and require the greatest expense to acquire more information; therefore, uncertainty is always high. Integrated genetic analysis provides a relatively rapid and cost-effective way to maximize the value of existing information and reduce exploration uncertainty in the most data-challenged settings.

Introduction
The spatial distribution and physical characteristics of coarse-grained clastic reservoirs and of fine-grained clastic seals is a function of the entire genetic history of the sediments (1–6). The history includes:sediment generation -from what materials, and under what conditions, the sediments were produced;sediment transport - how far, and by what mechanism, the sediments were moved; andsediment deposition - by what processess, and in what geometry, the sediments were placed in their final resting spot.
In basins where the spatial distribution and physical characteristics of the sediments cannot be easily observed or reliably inferred, reconstructing possible genetic histories can provide testable hypotheses about the nature of the sediments that reduce exploration risk. We have developed a systematic approach to using genetic-history information for play-element prediction. The success of the predictions can be assessed to improve the quality of future predictions.
Geology Drives Technology - Application of Coil Tubing Underbalanced Drilling in the Cooper Basin, Australia
Authors: Telesford Arthur Linus , Cheong Sharon Kah Heng , Cotton Timothy Brett , Chipperfield Simon T. 
Published: November 2008

Abstract
Record breaking oil prices and the forecasted upward pressure on gas prices form an exciting future for Australia's hydrocarbon industry. This commercial back-drop is creating a heightened interest in new technologies capable of improving recovery factors and accelerating production particularly in brownfield environments.
One such technology is Coil Tubing Under Balanced Drilling (CTUBD). While CTUBD is not a new technology, it is largely unproven in deep, hot, hard-rock environments such as the Cooper Basin, Australia. This paper outlines the rationale for applying CTUBD in the Cooper Basin which is founded on a fundamental understanding of the geology. The value of CTUBD is based on reviewing incremental reserves from the following three sources; the benefits of lowering the reservoir abandonment pressure due to the addition of damage free wells,the acceleration of reserves from extended production tails into the current economic window andincremental reserves obtained from accessing previously un-drained sands.
A methodology for determining the value of CTUBD based on the first point is the focus of this paper.
Finally, the paper presents an in-depth review of a five well campaign in Field A, distilling the results into an improved candidate selection methodology that can be applied to future campaigns.

Introduction - Field A Development History
Field A is one of the largest and most mature gas fields in the South Australian Cooper Basin. The field was discovered in 1966 with first gas online in 1969. Base field production contains large 'tail gas' that would become reserves if it could be accelerated ahead of the plant economic limit. The potential 2P reserves contained in the "tail" is approximately 20Bcf. Acceleration of tail gas (ie economic capture) has been partly addressed with stage wise compressional upgrades commissioned in the mid 1980s, late and 1990s.
Field A currently has 33 active gas producers and has produced approximately 595Bcf (Figure 1). Initial well online rates have ranged between 5–15mmscf/d. The performance of high rate wells is thought to be attributed to the intersection of high permeability streaks which are evident from core within the target sands. Field wide static gradient and Pressure Build-Up surveys (PBUs) were performed over the period 1989 - 1991 which revealed that the pressure depletion across the field varied widely and that many wells were subjected to high near wellbore skin damage due to poor drilling and completion practices. Presently, reservoir pressures are observed to be between 650psia to 1000psia from an initial pressure of approximately 3400psia.
Optimizing Well Integrity Surveillance And Maintenance
Authors: Kairon Saadon Bin , Lane Thomas Matthew , Murrey Michael David 
Published: November 2008

Abstract
ExxonMobil Exploration & Production Malaysia Inc. (EMEPMI) operates 17 offshore oil and gas fields in the Malay Basin. EMEPMI performs well integrity operations and maintenance on 37 platforms involving 781 wells with 1215 completions (single and dual wells). There are about 350 wells on gas lift, 1215 surface controlled subsurface safety valves (SCSSV), with 6943 tree and wellhead valves. The fields produce approximately 150,000 bopd and 1.2 BCFD of gas.
In this mature asset, many wells were previously un-competitive or uneconomic to flow. In today's higher-price environment, all wells are being re-evaluated for their production contribution. This paper describes the issues and actions taken for these "moth-balled" idle wells to ensure that they comply with the EMEPMI well integrity surveillance and maintenance standards for offshore platform facilities. At the same time, the effort was broadened to check and ensure the integrity of all active completions. The EMEPMI well integrity surveillance and maintenance standards are based on API and industry standards, as well as the global ExxonMobil well integrity standards.