bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development and Performance of an Eco-Friendly Cross-Linked Polymer System for Water Shut-Off Technique
Authors: Sengupta Baisali , Sharma Virender Parkash , Udayabhanu G. 
Published: March 2015

Abstract
Excessive water production is a serious issue to be dealt with during oil production from reservoirs. The use of gel as the water shutoff agent has been widely reported in enhanced oil recovery (EOR) for the development of mature oil fields. Polymer gels are used successfully in many reservoirs all over the world, but the problem lies in finding the suitable and economical polymer for the harsh reservoir conditions of high temperatures and salinity. The organically cross-linked polymer systems are being widely used due to their greater thermal stability and their applicability over wide pH range.
Many organically cross-linked polymer gels have been developed till date but most of them suffered setbacks due to their inefficacy at high temperature and salinity, carcinogenicity or non eco-friendliness. In the present work an eco-friendly organically cross-linked polymer system of Hydroquinone (HQ)/Hexamethylene tetramine (HMTA) cross-linked polyacrylamide (PAM) has been developed which is suitable for water shut-off.
The gel formed by cross-linking HQ and HMTA with PAM is found to have high mechanical strength, form gels at high temperature of about 120°C and retain stability for long periods of time. The performance of this system has been studied both by bulk gelation as well as in-situ gelation techniques. The gelation temperature was varied from 85°C to almost 120°C to study the variations in the performance of the polymer system. The in-situ gelation study was carried out by means of sandpack core flooding.
The present gel system is very efficient in water shut-off technique and can be applied in oil fields without much damage to the environment as both HMTA and HQ are ecofriendly with HQ being harmful to aquatic life to some extent. The performance and efficiency of this polymer system in an oil field has been judged from core flooding experiments.
Successful CTU Catenary and Well Test Operation on BY Drilling Platform
Authors: Sapian Mohd Reduan , Nordin Muhammad Helmi , Sharief Saeed Mohamed , Budi Setiawan Trigunadi , Khalid Mohd Zaidan 
Published: March 2015

Abstract
Field BY Coiled Tubing (CTU) Operation comprised of 2 wells to be cleaned out and perforated that are A1 and A4. These two wells target reservoir was untapped and has good potential of increasing gas production rate from BY Field.
Well A1 is an infill well while A4 is a workover well, which both operations were commenced in October 2009 using a jack up drilling rig. Problem started when these wells experienced held up as there was solid restriction inside the liner, which prevented further movement of the wireline tool and as such, perforation can't take place. After considering the escalating daily spread cost, in February 2010, decision was made to release the rig and temporarily suspend the wells for future well intervention.
Few options were available for the intervention job. After assessing all risks, the drilling team has decided to deploy CTU operation with Catenary system. This operation was considered unique and the first for Drilling Departrment. The challenge was high for the inexperienced team in handling the CTU Catenary operation. With shear determination and commitment, the drilling team managed to deliver the operation, where both wells were successfully cleaned out, perforated and flowed exceeding the minimum target.
This paper discusses the challenges faced by the drilling team in carrying out the CTU operation and lessons learnt throughout the operation.

Introduction
Upon suspension of well A1 and A4, the drilling team has started to look for solution to carry out the intervention job. Factors like cost, rig availability, effectiveness and offshore/weather condition played important roles in making the decision.
Based on detail technical discussion, the team had decided to use Rig-less CTU Catenary system. Instead of rig, a workboat was required to support the operation. It allowed Catenary system equipments (Coiled tubing Reel, Catenary System Power Pack, and Coil Feeder) to be positioned on a workboat and at the same time provided space for temporary storage of other major equipment such as tank and silos for clean-up fluids storage. Other major equipment were CTU Power Pack, Control Cabin, Injector Head stack up and flying Gooseneck were positioned on platform deck. Besides that, the platform was loaded with Well Testing equipment to control the flow by choke manifold and disposal of return from the wells by flaring through Burner Boom. On the other hand, a Slick line and Wire line equipments were placed on the platform deck for the purpose of tubing clearance check and perforation operation respectively. Using a workboat essentially saved the overall project cost because the daily charter rate for a workboat package including one support vessel is a quarter of a standard jack up rig daily cost.
Nam Con Son Basin Analysis: The Old and New
Authors: Meyer Kevin E. 
Published: March 2015

Abstract
Recent drilling results and activity has created a renewed interest in the Nam Con Son basin in Southern offshore Vietnam. This renewed interest follows several phases of exploration in the Nam Con Son Basin in which initial drilling and data collection allowed for the definition of a tectonic and stratigraphic definition of the Nam Con Son Basin. Incorporating the existing tectonostratigraphic interpretation with data acquired since the initial drilling campaign in the Nam Con Son Basin, Talisman Vietnam has successfully entered into the Nam Con Son Basin (NCSB). Successful integration of existing literature, tectonic models, detailed mapping, stratigraphic analysis, paleogeography and basin modeling have been used to develop an updated view of the petroleum system in the NCSB. This examination of the NCSB petroleum system presents a more complete history of the basin and therefore, a better understanding of the evolution and subsequent hydrocarbon potential.
Previous workers like Matthews (1997), Hutcheson (1989), and several other authors have been instrumental in outlining the basin history and tectonic development of the NCSB. For the purposes of this paper we will use the same naming conventions developed by Matthews (1997) in order to create some continuity between previous authors and any new interpretations. By using seismic data and a range of geologic information, key basin elements have been updated and in some cases, models challenging previously accepted ideas will be proposed for the NCSB. Regional seismic mapping and a clear understanding of the relationship between tectonics, accommodation space and sedimentation rates on a regional scale have changed our view of paleogeography and added details to the regional source and reservoir distribution models. These workflows and new ideas have allowed for the identification of areas of interest in the deepwater that will be drilled in the near future to test both old and new ideas in the NCSB.

Basin Fill Definition
The NCSB can be subdivided into four major tectono-stratigraphic units or megasequences; although other authors have further subdivided the stratigraphy, for the purposes of this paper, we discuss only these four major units. These megasequences have been subdivided primarily through an understanding of the effects of tectonics and relative sea-level on sedimentation patterns over time. The dominant mechanism, whether tectonics or sea-level, controlling basin fill over time remains unchanged within individual megasequences. This definition and subdivision plays a crucial role in understanding the various components of the basin and aids in developing predictive models for basin analysis in areas that lack significant data. The overall balance between tectonics and relative sea-level combined with other concepts like sedimentation rates, accommodation space and differential compaction are the basis for the introduction of additional granularity within the NCSB.
IPTT vs. Well Testing and Deconvolution Applications for the Thinly Bedded Reservoirs: Case Studies from the Gulf of Thailand
Authors: Kiatpadungkul Wiriya , Daungkaew Saifon , Chokthanyawat Suchart , Promkhot Soontorn , Ayan Cosan , Houtzager Johan Frederik , Platt Christopher J. , Storer Alexander James , Tabmanee Piyatad , Panyarporn Pantaporn , Voradejviseskrai Suttapan , Limniyakul Theeranun , Last Nick 
Published: March 2015

Abstract
In Asia Pacific region, there are many thinly bedded reservoirs which are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds. These reservoir sand bodies range from millimeters to tens of meters in thickness. Though the reservoirs are highly permeable, reservoir heterogeneity caused by silt and clay laminations affect recovery and sweep efficiency.
The typical way to test such formations is to use full scale well testing, even for relatively thin zones. In the Gulf of Thailand (GoT), a Tubing Stem Test (TST) is widely used to test each individual zone for reservoir parameters. During a TST, quartz gauges are run on wireline and the selected zone is perforated. While wireline Formation Testers (FT) have also been increasingly used in the GoT for measuring formation pressure, mobility and collecting reservoir fluids, more advanced FT tools, e.g. dual packers and Downhole Fluid Analyzers (DFA) were recently introduced to test each zone to help defining reservoir characteristics in more detail. A single probe FT deployed for pretests and fluid sampling can be used to obtain transient data during the shut-in periods after sampling in relatively thin zones. The data from these Interval Pressure Transient Tests (IPTTs) can be used to interpret reservoir parameters such as vertical to horizontal permeability ratio and horizontal permeability.
This paper discusses the uses of such smaller scale pressure transient data (single probe, dual packer formation testers) and full scale well testing using a simulation model and actual field data from the GoT. First, a single well simulation model is used to investigate the effects of thinly bedded shales at different scales on pressure transient data. The actual field data were then analyzed to obtain reservoir parameters and compared with core and PVT lab results. This paper also investigates the use of deconvolution applied to pressure transient tests of different scales to understand the effect of reservoir parameters using simulated and field data.

Introduction

Thinly Bedded Reservoirs in the Gulf of Thailand
In the Tertiary Basins of the Gulf of Thailand and Northern Malay Basin, thinly bedded hydrocarbon sandstone reservoirs have been encountered in several geological settings. In the northern Gulf of Thailand, Kra Basin, subaqueous lacustrine fan delta sandstones of between 1 to 4 feet have developed as a result of episodic deposition. In the Southern part of the Pattani Basin adjacent to the Narathiwat High, thinly bedded reservoirs of less than 1 to 7 ft were deposited in marginal marine, tidally influence estuarine channel fills settings and also in more proximal fluvial crevasse splay deposits.
S1 Asset Integrity Model and Management System (AIMS)
Authors: Sri-amorntham Apisak , Chinpongpan Roungwit , Chansakran Anan 
Published: March 2015

[Abstract]
Sirikit oilfield; a better known as S1, has steadfastly delivered petroleum products to serve its country for 28 years. With its dedication towards corporate vision fulfillment, a target in 2010s decade which challenges this matured S1 asset is to maintain production of 20,000 BBLD through operation excellence and holistic sustainability.
AIMS has been realized and become a key tool in achieving its goal. The prime objective of S1 AIMS is to ensure that S1's internal resources including people, systems, processes, and plants are adequately deployed whilst performing intended functions without abusively utilized. Most of them have to be assured due fit for their purposes over their entire lifecycle in order to efficiently and effectively deliver production at minimum of 20,000 BBLD net crude until at least 2020 where risks associated with accident, safety and environmental aspects as well as loss of production are practicably kept at minimum while stakeholder values are also sustainably maintained.
Unlike other asset integrity concepts S1 foresees the importance of external factors associated with its asset integrity. The concession area covers 4 provinces. More than 400 wells are located near the villages. The asset is cognizant of community values through its kind citizenship and neighborliness where sustainable growth of asset and community becomes mutually inseparable. In addition, some external resources including authorities, contractors, and service providers are regarded as non negligible factors which also hold influenced over S1 integrity.
This paper outlines how S1 develop an asset integrity model for their matured oilfield in a holistic approach underlying with their experiences passed to following generations. They take both internal and external factors into this model. The paper aims to show how this oilfield implements their AIMS as a bridge to attain their vision. Various components in AIMS have been built. S1 AIMS has been implemented to correspond to such the conceptual model. Several actual cases are demonstrated with lessons learned and the way forwards. Some pilot initiatives which are widely accepted as good practices for other projects to follow and further development to be corporate standards and practices.
Petroleum System Analysis Using Geochemical Studies, Isotope and 1D Basin Modeling in Hendijan Oil Field, SW Iran
Authors: Hassanzade Ghanbar , Kobraei Mehdi , Ahanjan Asghar , Bagheri Tirtashi Rahim , Rashidi Mehrab , Khaleghi Mehdi 
Published: March 2015

Abstract
Hendijan oil field is located in north of Persian Gulf and is producing oil from 3 different reservoirs. Geochemical studies of candidate source rocks have revealed that four interval of source rocks exist in this region that could generate hydrocarbons. These formations include: Pabdeh (Tertiary), Kazhdumi (Albian), Garau (L. Certaceous) and Sargelu (M. Jurrasic).
Oil-Source rock correlations are based chemical properties, biomarkers, C13 Isotope and other geochemical indices. Geochemical analyses done in Hendijan oil field have shown that Kazhdumi and Garau formations are the most important source rocks in the region. Pabdeh formation is excluded from possible source rocks due to its low maturity. No geochemical analyses have done on Sargelu formation. Different geochemical analyses including GC, GC-MS and Isotope (Carbon and Sulfur) have done on 3 oil samples from Asmari (Tertiary), Sarvak (M. Cretaceous) and Nahr Umr (E. Cretaceous) reservoirs. In addition, burial and thermal history modeling was performed to determine timing of hydrocarbon generation in the candidate source rocks in studied field. Geology and sequence Stratigraphy analysis of borehole data including drill-cuttings provided fundamental constrains for burial history reconstruction. One-dimensional model of thermal evolution were derived from the burial history and calibrated with Vitrinite reflectance, thermal conductivity, surface and bottom-hole temperature measurements, as well as with paleoclimate data.
Regarding geochemical analysis on several oil samples, all the reservoirs have been charged by one source rock. Biomarkers and isotope data indicate that Kazhdumi Formation correlates best with oil samples.
In addition to geochemical analysis, 1D petroleum system modeling shows that Kazhdumi and Garau source rocks reached oil generation window in 3 and 4 MY ago respectively and both of them are still in oil generation window. But lack of Oleanane biomarker in analyzed oil samples and low TOC content of Pabdeh formation confirms no charge of reservoirs by tertiary candidate source rock (Pabdeh).
Unconventional Reservoirs Probabilistic Reserve Estimation Using Decline Curves
Authors: Minin Antonio , Guerra Laura , Colombo Ivan 
Published: March 2015

Abstract
The purpose of this work is to propose a methodology for Reserve Estimation in Unconventional Reservoirs, based on a set of production forecasts, generated from decline curves, that follow a probabilistic approach.
Because of these reservoirs nature, conventional Reserve Estimation methods are not capable of representing the intrinsic variability in unconventional wells behaviour.
Our goal is to provide a Reserve Estimation in terms of P10, P50 and P90 based on Decline Curves.
From a reference database we defined sets of Cumulative Distribution Functions of initial rate, decline exponent and initial decline ratio.
Sampling randomly among these CDFs with a Montecarlo approach, different "scenarios" - sets of the decline parameters - were created. Each of them generates a single decline profile.
So we got a set of decline curves, which allow us to reproduce the behaviour of an unconventional play: all the wells do not perform exactly in the same way the "average" well do, but they behave in slightly different ways, due to different play areas or different completion techniques applied.
This variability reflects in wells initial rate or curvature and decline of the production profiles, represented by the bunch of decline curves.
So it's possible to forecast an unconventional play field production with a considerable variability, taking into account the natural differences between wells in such environments.
For our analyses, we used a reference database of about 150 wells: 50 of them were used to extract decline curve parameters and distribution, and the remaining 100 were used as check data to assess the validity of the methodology.
We investigated several ways to combine the scenarios together, in order to obtain reliable range of variability of field production.

Introduction
Natural gas is stored in Gas Shale as free gas in rock pores (reference porosity) and natural fractures and as adsorbed gas on organic matter and mineral surfaces. The relation between these different storage mechanisms affects the evolution and the shape of gas production profile. Since this kind of reservoir has such low permeability (from 10-4 mD to 10-8 mD), it releases gas very slowly and time to reach (pseudo) steady state conditions is extremely long. The production mechanism by which gas is produced from a shale reservoir involves depletion of the fracture network and the matrix and desorption of the gas from kerogen. The gas in the fractures is produced immediately while the gas adsorbed onto organic matter is released as the formation pressure declines. Due to the limited storage capacity of the fractures, the initial gas rates will decline steeply as free gas in the matrix is being produced, and eventually stabilize when desorption begins to dominate production. The desorbed gas moves slowly through the shale matrix by diffusion, until it reaches a fracture so it can be collected in the wellbore.
Interpreting Geological Systems from Seismic Attributes: Reasons for Caution from the Northern Malay Basin
Authors: Barr Duncan Charles , Flynn Mark John , Ong Cheng-Sun , Dharmarajan Krishnan 
Published: March 2015

Abstract
Seismic attributes are routinely used to interpret depositional patterns, particularly where channel systems form the main reservoir sands. This paper presents an example of an apparently clearly imaged channel-like feature, the size of which did not match that implied by pressure transient analysis.
The anomaly in question is a relatively straight, sharp-edged, channel-like feature interpreted at a TWT depth greater than 2 seconds. An appraisal well was drilled through the feature, encountering a gas-charged sand at the interpreted level in the well. A drill-stem test (DST) was conducted, and gas was produced to surface in a sustainable manner. Based on the combination of seismic attributes and well data, the sand body was geologically interpreted to be a relatively clean, tidally reworked sand deposited in a linear incised valley, with thickness-width ratio of around 1:30. This ratio is considered narrow for the depositional setting, but is within published ranges for channel systems.
When the DST results were subjected to Pressure Transient Analysis (PTA) and dynamic modeling, the technique implied that the sand had a drainage radius several times that indicated by the seismic attribute. Subsequent re-interpretation of the seismic anomaly has led to the conclusion that the seismic attribute did not image the reservoir sand. Rather, the attribute is now thought to indicate an erosional cut through a coal bed, which by coincidence overlies a gas-filled sand.
The discrepancy between the seismic interpretation and the well test result has implications for volumetric estimates. Long-term production testing is therefore being considered in order to better-define the lateral extent of the reservoir. In the meantime, a high level of caution will be applied to the interpretation of seismic images from deeper reservoir intervals.

Introduction
Carigali Hess operates four gas fields within Block A-18 (Figure 1) of the northern Malay Basin: Cakerawala, Bumi, Suriya and Bulan. Gas pay in these fields occurs within multiple, stacked sandstone reservoirs that range in depth from less than 4,000 ft to greater than 10,000 ft subsea. A 3-D Q-Marine seismic survey was acquired in 2006, and attributes from this survey have been routinely used to successfully identify and target gas pay sands in the shallower reservoir intervals. Seismic attributes have also been used on deeper reservoir intervals in order to identify potential reservoir bodies.