bluuebunny/crossref_metadata_2025_split huggingface dataset:
At an Investment Crossroads: Malaysia Versus Indonesia
Authors: Abidin Faris Anwar 
Published: October 2015

Abstract
Malaysia and Indonesia have experienced changes within their oil and gas industry in recent times. In 2010 and 2011 respectively, the introduction of GR 79 in Indonesia and the emergence of Risk Service Contracts (RSC) in Malaysia have caused investors to re-assess their opinions on these two burgeoning countries as potential business ventures.
In this paper, Production Sharing and Risk Service contracts that are applied in Malaysia will be compared extensively with the active contracts that are practiced in Indonesia by outlining the key differences in commercial terms with the use of a discounted cash flow model. The analyses were done using real analogue cases and normalized for comparative purposes between the two fiscal structures, and assist industry players to understand the merits, requirements, and pitfalls of the oil and gas fiscal regimes in these countries.
The impact of both fiscal regimes on the economic indicators of a project are distinctive, due to differences in cost recovery mechanism, revenue allocation, domestic market obligations, royalties and taxation policies. This paper therefore serves as a review and showcase of the differences in oil and gas fiscal regimes between Malaysia and Indonesia.
IOR Engineering Philosophy in Brownfield--Case Study
Authors: Yang Siyu , Liu He , Lian Liming , Yang Yongzhi 
Published: October 2015

Abstract
Continental sedimentary sandstone oilfield in China, represented by the Daqing Oilfield, locates in northern Songliao basin, eastern China. The field produces from several sand intervals in mid-Cretaceous Saertu, Putaohua and Gaotaizi groups, large River Delta sediment, the net pay is 500 m. Daqing oil field has been producing since 1960, water injected almost simultaneously, from 2000, ASP flooding has been applied on a large scale, commercial application has been implemented in three regions, oil recovery have been enhanced by 20% compared with water flooding. Currently, oil recovery factor for Daqing placanticline is 40%, water cut is 92%.
Modified Approach Leads to Successful Off-Bottom Cementing Plugs in Highly Deviated Wells in the Caspian Sea
Authors: Isgenderov Islam , Taoutaou Salim , Kurawle Irfan , Mesa Alvaro Martin , Khan Tariq 
Published: October 2015

Abstract
Certain abandonment operations require plugs to be set off-bottom in a well. The challenge in setting plugs in highly deviated wellbores lies in obtaining a competent hydraulic seal that can qualify as a barrier to any potential flow zones. Failure to achieve a good cement plug leads to increased nonproductive time (NPT) from cleanout, drillout, and setting additional plugs. Small slurry volumes, unstable fluid interfaces with respect to gravitational forces, and fluid contamination add to the complications. In the Caspian Sea abandonment operations, plug-placement simulation aided in designing cement plugs and setting procedures in inhibited seawater, water-base, or oil-base drilling fluid environments. The advanced cement plug placement simulator was used to design fluid properties and optimize volumes for plug-placement operations in highly deviated Caspian Sea wells.
For successful placement, physical fluid properties and fluid mechanics were used in the advanced placement simulator; in addition to the fluid behavior, the simulation took into account well geometries, tubular dimensions, and mechanical separation devices. Various parameters affecting successful plug placement, including but not limited to, length of tailpipe, gel strengths, underdisplacement volumes, and placement procedures were input into the simulations. Balanced cement plug placement is widely practiced by many operators. In the literature, it has been shown that when smaller diameter tubing or tailpipe is run on the bottom of drillpipe, the assumption that all fluids both inside and outside the drillpipe will remain in hydrostatic equilibrium is wrong. In this study, advanced placement modeling illustrated that an initially balanced cement plug may become unbalanced while pulling a cement string with tailpipe out of the hole. Multiple abandonment operations performed in Caspian Sea wells provided key lessons for wellbore preparation, fluid design, and wellsite execution. Design decisions made from the simulation results and improvements made with implementation of industry best practices increased the ability to get plug placement right every time from the first attempt.
Deepwater Exploration Breakthrough with LWD Technology in South China Sea
Authors: Cai J. , Cheng Y. F. , Chen M. , Shim Y. , Liu P. , Jiang Y. , Liang J. , Munoz D. H. 
Published: October 2015

Abstract
For CNOOC ZhanJiang branch (CCLZ), 2014 was a milestone year where for the first time, they managed their deepwater exploration in Lingshui 17-2 (LS17-2) block independently, without the involvement of other international oil companies. CCLZ faced many drilling challenges in their six-well deepwater project, including stuck pipe, kick and mud losses due to wellbore instability, as experienced on previous five exploration wells drilled in nearby area. The occurence of these events has the potential to increase operational cost and risk.
The sedimentary geology in Lingshui block is complex, and the downhole environment is challenging as the pore pressure ramps up quickly above the reservoir resulting in a very narrow mud weight window. To address these challenges and drill the wells safely, the exploration project management team decided to employ real-time geomechanics monitoring. A mechanical earth model (MEM) was constructed before drilling to define optimized wellbore stability boundaries and identify potential hazards associated with the planned trajectory. Based on the real-time logging while drilling (LWD) data, the MEM was updated and drilling parameters adjusted to keep within operational limits.
Using LWD data, the pore pressure was calculated in real-time and verified against other drilling observations, such as connection gas, flow tests, drilling parameter analysis and caving analysis. The fracture gradient was calibrated against a formation integration test (FIT) at the casing shoe. These real-time updated fracture gradient and pore pressures were then applied to keep mud weight and equivalent circulating density (ECD) within the narrow safe mud weight window. Upon completion of the well, real-time pore pressures predictions were compared with actual pressure measurements in permeable sandstone intervals, and the results found to match very well. This provided the drilling team with confidence in both the real-time data quality, and the accuracy of the pore pressure prediction. The application of the measurements while drilling and the resulting reduction in uncertainty meant that the 16" casing was not required in the next four deepwater wells, saving USD8 million per well and significantly impacting the economic efficiency of this project.
Simulation Study of In-Situ CO2 Huff-n-Puff in Low Permeability Fault-Block Reservoirs
Authors: Wang Yong , Hou Jirui , Song Zhaojie , Yuan Dengyu , Zhang Jingwei , Zhao Teng 
Published: October 2015

Abstract
The in-situ CO2 huff-n-puff (ISCHP) is a promising EOR technique that could overcome some major drawbacks associated with continuous CO2 flooding, e.g., early CO2 breakthrough, high operation costs, demand for CO2 source, etc. Field pilot test of in-situ CO2 huff-n-puff was carried out in Jiangsu Oilfield based on lab experimental study, which results in the augmentation of well productivity and water cut reduction.
Our work is to develop the kinetics model of gas generation reaction of the pilot and discuss ISCHP mechanisms base on reservoir simulation. Through in-laboratory experiments, a salt solution with surfactant additives (gas generation reagent) was injected into the sand pack model to evaluate ISCHP efficiency. The kinetics model of gas generation reaction was developed by matching the decomposition experiment results of the pilot. According to the reservoir geological characteristics, a reservoir model was built and calibrated based on the past production observations of the pilot. Furthermore, a series of sensitivity analysis of the operating parameters, including concentration of the reagent, injection volume and soaking period, were conducted to obtain the optimum scheme.
Reservoir simulation illustrates the reagents can generate large amount of CO2 near the wellbore formation. ISCHP process can increase oil production by 56%, and decrease the reservoir temperature near wellbore by 5°C with the endothermic decomposition. The most influential parameters are concentration of the reagent and injection volume. Besides, the optimum scheme is achieved with a 16.4 wt% concentration of the reagent, an injection volume of 250t, and a soaking period of 7 days. This study can provide fundamental understanding of ISCHP enhanced oil recovery in the Jiangsu oilfield.
Case Study: Reservoir Management of Kerisi Field - Lesson Learned After Seven Years of Production
Authors: Faisal A. , Mlacnik M. J. , Harahap A. E. , Ramdani D. A. 
Published: October 2015

ABSTRACT
The paper describes the reservoir management experiences of Kerisi field after seven years of production. Kerisi field is located in Block B of South Natuna Sea and comprises five separate reservoirs in three geological zones.
Forty seven percent of the reservoir hydrocarbons are located in the Upper Gabus Massive West (UGMW) reservoir; optimum production from this formation is expected to be reached by injecting gas at the gas cap. The source of injected gas is from all five Kerisi reservoirs and the nearby Hiu field. The liquid hydrocarbon production from UGMW and the production/injection of Kerisi – Hiu produced gas in this formation is of high importance to the future development stage of Kerisi – Hiu field.
The initial reservoir management strategy was to optimize oil value with injection while meeting gas sales requirements. Both gas sales commitments and injection targets were honored with high Kerisi – Hiu production and the strong performance from other gas fields.
With time, other gas fields became depleted faster than expected. Thus, it was decided to reduce gas injection rate in UGMW and produce more Kerisi and Hiu gas to increase gas sales volumes. The reduced of injection rates improved short term economic of the fields, but the effect to reservoir and long term economic benefit still needs evaluation.
This paper will (1) show the impact of varying injection rate at UGMW to the overall Kerisi – Hiu field future production, include oil, gas, condensate, and LPG, (2) discuss an updated – improved reservoir management strategy, and (3) present an economic evaluation of the updated reservoir management strategy for the Kerisi – Hiu fields.
The purpose of the paper is to share lessons learned in the evaluation of historical performance, data acquisition and monitoring, static and dynamic modeling, history matching, prediction of future performance, and the dynamics of reservoir management strategy which support future profitable opportunities.
Geopressure Prediction in Deepwater Southeast Asia: Case Study from Sundaland Borneo Continental Margin
Authors: Osundina Adekunle Olayinka , Simatupang Zulfikar , Kaeng Geovani C. , Sausan Sarah 
Published: October 2015

Abstract
Drilling into deepwater prospects of South East Asia have been very challenging especially in NW Borneo and subsurface hazards related to pore pressure and wellbore stability remain the greatest obstacle. A myriad of wellbore issues have led to failure of some wells to reach geological targets and the drilling cost as high as US$100 million (as of 2014) is not uncommon in the area. It is important to be able to understand the geological nature of pore pressure mechanism in deepwater Sundaland continental margin (DSCM) and thus redefine pore pressure prediction strategy in the area to better align with the regional characteristics.
The currently established empirical effective stress-based pore pressure prediction is dissected to reveal its pitfalls especially regarding its application to DSCM. Compaction mechanism assumptions are also revisited in depth. Three wells from a deepwater field in Northwest Borneo are used as a case study to demonstrate the distinct overpressure nature of the area.
This study confirms that DSCM not only exhibits overpressure profile typical to deepwater anywhere else, but also possesses distinct geopressure characteristics related to its unique geological setting, most notably the active compressional shortening of the mega thrust-fold belts accompanied by continuous rapid deltaic sediment deposition. As a result, unique geopressure-related challenges prevail in this area, such as: shallow top of overpressure, the failure of standard empirical compaction methods, and prominent centroid phenomenon.
It is successfully demonstrated that the shallow top of overpressure of DSCM is linked to rapid sedimentation of low permeability sediments; undrained tectonic shearing is the central cause of common underestimation of popular effective-stress based pore pressure prediction method; and that the dominance of compressional geological structures explains the high likelihood of centroid effect.
Evolution of Gas Detector Placement and ISA TR84.00.07
Authors: McGlone James 
Published: October 2015

Abstract
Many oil and gas facilities utilize fixed gas detection systems as a safeguard against uncontrolled release of hazardous process materials. The effectiveness of fixed gas detection systems is most often limited by the ability of the system to detect that a release has occurred. Obviously, the number of detectors and geographic placement of those detectors play a critical role in the capabilities of the system to detect a release. Traditionally, the number and placement of gas detectors has been based on rules-of-thumb and expert judgment, leading to inconsistent and sometimes ineffective systems.
In an attempt to establish a consistent and repeatable method for placement of gas detectors in industrial processing applications, the International Society of Automation (ISA) issued a technical report ISA-84.00.007-2010 Guidance on the Evaluation of Fire, Combustible Gas and Toxic Gas System Effectiveness. The focus of this report is to provide recommended practices for the design of fire and gas detection systems. Specifically, the technical report focused on development of a method to characterize the "performance" of an array of detectors, which is sensitive to detector locations, the number of detectors installed and potential sources of release. The methods for characterizing this performance has evolved into what is known today as "Fire and Gas Mapping" or "FGS Mapping".
Maximising Logging While Drilling Value in Carbonate Wells Drilled in Pressurised Mud Cap Drilling Conditions: Challenges, Solutions, and Advances
Authors: Kyi Ko Ko , Han Mei , Lee Samie , Roberts Iwan , Maeso Carlos 
Published: October 2015

Abstract
The interest in exploring carbonate reservoirs has experienced a rapid growth in south-east Asia. However, significant drilling hazards have been encountered where karstification and fractures are present. This led to deployment of pressurised-mud-cap drilling (PMCD) to address total losses. PMCD involves drilling with no returns to surface, while drilled cuttings are injected back to the lost circulation zones. Under the PMCD conditions, wireline logging is usually ruled out, making logging-while-drilling (LWD) the only choice. PMCD often induces adverse borehole conditions such as enlarged hole and deep early time invasion, which affect log responses and challenge interpretation. PETRONAS has reported several wells in which well logs were badly affected when PMCD was activated.
A recent carbonate gas well illustrates the impact on LWD responses of the deep invasion and borehole deterioration associated with PMCD. A multifunction LWD tool providing triple-combo logs, sigma, and spectroscopy measurements was combined with a high-resolution resistivity imaging tool to identify the gas-water contact. The hole was enlarged up to 10-inches, in contrast to the 8 ½ inch bit size. Reservoir evaluation was complicated by the following: Propagation resistivities read low in reservoir rock, erroneously suggesting a water zone; nuclear porosity (TNPH) was doubtful due to the effects of enlarged hole on the measurements; and there were no cuttings returns to confirm possible dolomite presence. To understand and discriminate formation response from the environmental effects, an integrated workflow was developed to provide information on rock texture and producibility.
Even though low in absolute value, propagation resistivities with multiple depths of investigation separate, suggesting conductive invasion. True formation resistivity can be resolved by 1D inversion of the resistivity array. The derived Rt is close to the laterolog-bit resistivity from the LWD imaging tool in both absolute values and profile, indicating a gas column section. To estimate porosity, three methods were compared, with the assumption that the formation was fully invaded: (1) Resistivity porosity obtained from inversion of Archie's law; (2) sigma porosity and (3) TNPH. TNPH was corrected for lithology effects by using LWD spectroscopy calcium and magnesium yields to quantify calcite and dolomite. For resistivity based porosity, variation in Archie m plays a key role. The results showed TNPH and sigma porosities were consistent with Archie porosity for m varying between 1.6 (fracture-rich interval) and 2.4 (predominance of vuggy pores). These textural variations are observed on the borehole images. The work demonstrated the value of integrating multiple LWD measurements to reduce uncertainties caused by borehole degradation and carbonate heterogeneity under challenging PMCD conditions.
A New Method for Overpressure Mechanisms Analysis
Authors: Satti Iftikhar Ahmed , Yusoff Wan Ismail 
Published: October 2015

Abstract
The knowledge of overpressure mechanisms is an important prerequisite of overpressure prediction. The mechanisms of overpressure can be identified using the pre-existing techniques of cross plotting the velocity versus effective stress and density. However, this paper discusses a new method of overpressure mechanisms analysis using the acoustic impedance. The acoustic impedance is calculated using sonic velocity and density log. The acoustic impedance log shows clear change in trend with increase in overpressure generated by fluid expansion mechanisms. Based on the change in trend of acoustic impedance, a relationship has been developed between acoustic impedance and mechanisms of overpressure.
Completely Cationic Drilling Fluid System Relieved Ultra-Deep Wells Drilling Difficulties
Authors: Li Ning , Shi Xiangchao , Li Jiaxue , Zhou Zhishi , Zhu Jinzhi , Shen Qinchang , Cai Wuqiang 
Published: October 2015

Abstract
When it comes to ultra-deep wells drilling, there are multiple difficulties to be considered: over-pull and blockage during tripping because of swelling of shale and clay, instability, and costly maintenance of traditional water-based drilling fluid in high temperature. In order to solve these problems, a completely cationic drilling fluid system with excellent inhibition and stability in ultra-deep wells has been researched.
The completely cationic drilling fluid system, characterized by a zero zeta potential differential between the fluid system and the formation to which it is applied, consists of cationic inhibitors, cationic coating agents, cationic fluid loss additives, cationic plugging agents, etc. Laboratory experiments have shown that the zeta potential of the optimal fluid system lies between −10 mV and −20 mV, which is slightly higher than that of the formation. Furthermore, the system exhibited excellent rheology properties, filtration control properties, and anti-contamination abilities of salt, calcium, and clay at 180 °C.
The completely cationic drilling fluid was successfully applied to more than 30 wells in an Haxinre oil reservoir located in the central of Tarim basin with depths over 6650 m and temperatures &gt;160 °C. The results show that the completely cationic fluid has particularly good inhibition, rheology, and filtration control properties at high temperatures, while it resists salting, clay, and gypsum contamination effectively. Compared with traditional fluid systems, wells using completely cationic fluids have ~10% fewer drilling problems, ~15% greater penetration rates, and ~10% reduced drilling periods. The best records include 59 days to finish drilling a 6700-m-deep well and 69 days for a 7300-m-deep well, which were about 30–50 days earlier than planned.
It is clear that the completely cationic drilling fluid system is an economic alternative for ultra-deep reservoir drilling.
A Mathematical Model for Calculating the Volume of Proppant in Shale Vertical Wells
Authors: Zeng Jie , Deng Yan , Guo Jianchun , Lu Cong , Gou Bo , Zeng Fanhua 
Published: October 2015

Abstract
Hydraulic fracturing, creating stimulated reservoir volumes, has been widely applied to obtain economic flow in shale gas/oil formations today. However, for a fractured shale vertical well, determining the volume of proppant placed into the pay zone still remains difficult. Previous methods are based mainly upon empirical approaches which, to a large extend, are uncertain and imperfect. This paper established a novel but simple mathematical model to calculate the volume of proppant, merely using optimized parameters of fracture network obtained from numerical simulation.
Since the permeability of fracture networks is several orders of magnitude larger than that of the reservoir and the geometry of them is considerably complex, the fracture networks are simplified as a high permeability zone (HPZ) according to the equivalent principle of seepage. HPZ units are selected to build this model based on the following assumptions: (1) the seepage flow in shale involves the matrix flow and fracture flow from HPZ units to wellbore under steady state, (2) a multilayer seepage model is utilized to describe the fluids flowing in HPZ unit and study the characteristic seepage behavior of dual porosity medium, (3) heterogeneity in fracture propagation direction is neglected, (4) the proppant is packed into the fracture uniformly.
The model reported here has been successfully applied to XC32 well in Sichuan Basin and its prediction is 408.8m3(40/70-mesh, ceramic proppant). In reality, 400.4m3 of proppant was used and fracturing monitoring showed that the HPZ parameters in the field (length 500~600m, width 130~200m) match well with previous optimized design (length 550m, width 100m). Besides, the resulting flow rate is 7.04×104m3/d in this case, which is a breakthrough for unconventional reservoirs in Sichuan Basin.
Because this model considered the vertical heterogeneity of the reservoir and simply utilized HPZ parameters, it is convenient and meaningful to direct the treatment design in the field.