bluuebunny/crossref_metadata_2025 huggingface dataset:
Volcanic Tight Gas Condensate Reservoirs: An Integrated Approach to Performance Analysis in Raageshwari Deep Gas Field, India
Authors: Saurav Saurav , Gupta Abhishek Kumar , Shankar Pranay , Verma Sumil Kumar
Published: October 2015

Raageshwari Deep Gas Field, India is a low permeability (0.01-1md), medium CGR gas condensate reservoir. The pay-zone consists of a poorly sorted sandstone interval on top of stacked succession of thick lava flow cycles of volcanic origin. The field is developed with vertical wells and multi-stage hydraulic fractures. Developing a tight heterogeneous system comes with its own set of challenges – reservoir characterization and pay identification, fluid distribution, well placement, frac placement with optimum parameters, interconnected volumes, per well recovery, etc. This paper highlights our approach to mitigate various uncertainties to accurately predict field performance.

An extensive data acquisition plan coupled with 4 years of production history played a crucial role in identifying the correct solution set. Extended well testing was carried out for different wells during the appraisal phase. Pressure transient (PTA) data acquired during this period helped in estimating the "KH" of the various layers which was correlated with the log derived permeability and hence validating the petrophysical and geo-mechanical model. Similarly, other core and drilling data were incorporated into the model for proper reservoir characterization and pay identification. As more wells were drilled and brought on production, sufficiently long PTA was impossible. However, massive hydraulic fracturing campaign provided ample opportunity to conduct DFIT (diagnostic fracture injection test) for estimating the reservoir parameters as well as validate the model. Variation in fluid distribution across the section was expected as production data confirmed areal and vertical variation in CGR. Multiple samples were captured from different wells and a PVT model was created which justified the fluid produced. Application of Digital Oilfield ensured the continuous production data which was analyzed via RTA for guidance on "Per Well Recovery". This was integrated with traditional PTA, time-lapsed production log, core analysis and DFITs.

Such a complex system is best resolved using individual well analysis. A comprehensive workflow was created which ensured data acquired from all the individual wells were integrated and accordingly the petrophysical and geo-mechanical models were updated. The workflow permitted us to reduce our uncertainty on the key parameters of pay identification, frac optimization and Well Spacing. This improved our perspective of the field, and permitted us to optimize our field development, which is robust despite market uncertainties.

Few innovative ideas were used in our design for data acquisition to minimize the time constraint – such as extended DFITs, use of well-head pressure for PTA using an accurate well-bore model, time-lapsed flowing pressure and PLT data to study the effects of changing productivity etc. These innovations helped us move down the uncertainty ladder quickly with a high degree of confidence.
Optimum Competency Development and Career Path - Skillmap Approach
Authors: Nishi Masatoshi , Yoshida Takeshi , Yasuda Chika
Published: October 2015

An Accelerated competency development is one of the essential factors to achieve and sustain the medium- to long-term vision of INPEX. After intensive reviews and discussions, a skillmap based development approach had been selected and implemented especially targeting young technical professionals to enhance the company's overall technical capabilities. This paper describes the key success factors of our Skillmap set-up approach and its implementation procedures.

The internal discussion concluded that we required "own" style of competency development scheme rather than utilizing a ‘ready-made" scheme or contracting out. Three key points of our approach are highlighted as follows. Job matrix and skill matrix: Two matrixes were created to evaluate the work experiences and technical capabilities respectively for the optimum development plan.A face-to-face approach: This is our core approach of communication, to build strong relationship between young and senior professionals.A dedicated competency development support team, so-called "Skillmap team", leads the entire process proactively.

The approach was implemented nearly two years ago and over 150 young professionals have experienced the processes.
At an Investment Crossroads: Malaysia Versus Indonesia
Authors: Abidin Faris Anwar
Published: October 2015

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

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

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

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

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

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

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

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

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

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

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 >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

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.
A Novel Approach to Determine Minimum Riser Top Tension Setting and Comparison with Traditional Methodology – Analytical Case Study
Authors: Thomas Reena
Published: October 2015

As the development of offshore hydrocarbon reserves extends into greater water depths, the drilling riser requirements and limits have become more onerous due to harsh environmental conditions and uncertainties involved in response prediction. The dynamic response of the vessel to environmental conditions can significantly impact the response of the riser tensioner systems. In the case of deep-water drilling applications, as per API RP 16Q, the riser string must always be in positive effective tension. However, in the case of modern riser tensioner systems, which have non-linear stiffness and damping characteristics, the effective tension in the riser can vary substantially as the tensioner strokes in response to vessel heave. In order to accurately predict the loads on the riser using finite element analysis, the tensioner system has to be accurately modeled in great detail.

This paper presents a comparative analysis of direct acting and wireline tensioner system responses for a range of environments using a top tension setting calculated as per API RP 16Q. The detailed tensioner model used for the analysis has been validated against manufacturer performance data for existing in-service tensioner systems and includes the individual hydraulic and pneumatic components of the tensioner system. A non-linear structural FE analysis tool is used to model the detailed tensioner model as part of a drilling riser string.

The analysis results show that there are large percentage variations in the effective tension at a given point along the riser. The dynamic tension variation displays an increasing trend as the heave velocity increases. An alternate method to calculate the top tension setting and it's impact on the minimum effective tension along the riser string is discussed herein.
Synthesis and Evaluation of A Macromolecular Viscosity Reducer for Venezuela Heavy Oil
Authors: Bin Ding , Xiangfei Geng , Lipeng He , Baoliang Peng , Jianhui Luo
Published: October 2015

Orinoco heavy oil belt in Venezuela is a world-famous heavy oil belt, and difficult to develop due to the high viscosity of crude oil. In order to reduce the viscosity, a water-soluble macromolecular viscosity reducer (commercial name: CVR-V) for MPE3 block is designed and prepared. It is synthesized via copolymerization, and plays an important role as emulsifier in forming O/W emulsion. The experimental results demonstrate that CVR-V show extremely superior initial viscosity reduction effect and the O/W emulsion stabilized by CVR-V exhibits excellent static and dynamic stability. The optimum condition for viscosity reduction is obtained: with the ratio of 10:3 (oil to water), and 0.1 ~ 0.2% of viscosity reducer, the initial viscosity reduction rate reaches 99.8% approximately and the apparent viscosity is less than 100 mPa·s. Meanwhile, excellent static and dynamic stability are proved, i.e. the apparent viscosity of O/W emulsion is still less than 500 mPa·s after standing for 60d for static stability tests, and is also less than 200 mPa·s in rotation 7d later by vertical loop for dynamic stability tests. Laboratory experimental results demonstrate that the fluidity of Venezuela's ultra heavy oil can be greatly improved by CVR-V, and CVR-V exhibits strong potential in development of Venezuela heavy oil.
Use of Cluster Analysis to Improve Representative Model Selection: A Case Study
Authors: Baker Mark
Published: October 2015

An accurate representation of the range of possible subsurface outcomes is critical for effective appraisal and development of petroleum resources. The infinite number of possible subsurface realisations is typically represented by a small number of representative reservoir models that are then used for more detailed analysis. This study investigated the applicability of cluster analysis to deterministic model selection for an undeveloped gas reservoir, using the results of response surface models. Two cluster analysis techniques were compared against standard model selection methods. Cluster analysis was found to perform better than traditional methods of model selection in generating robust, representative and varied models for scenario analysis and development planning. Generalised sensitivity analysis, GSA, was performed to complement the model selection process.
Deepwater Facility Integrity Management: A State-of-the-Art Review
Authors: Allen Eric
Published: October 2015

The offshore oil and gas industry recognizes and agrees that there are too many instances of premature failures leading to loss of life, environmental impacts, reputation damage, increased downtime, and production losses. In response to this situation, there has been rapid growth in integrity management related research and development, however it has become difficult to keep track of all of this activity. The purpose of this state-of-the-art review paper is to summarize key findings and provide a comprehensive list of pertinent literature in the field of deepwater facilities integrity management. Focus is given to the latest information on integrity management systems, regulations, standards and recommend practices, and current industry challenges. The goal of this paper is to consolidate and provide the most updated information regarding integrity management, in order to assist those individuals and companies that are new to this field. Several of the referenced documents are available to the public via the World Wide Web. The references are provided for information only, and do not represent a comprehensive list of applicable standards, recommend practices, or regulations.
Managing Integrity and HSE in a 40 Years Old Installation
Authors: Aryaguna A. , Razy F. , Hadipamenang S. , Haekal T. , Pranyoto P. , Sudjarwadi S.
Published: October 2015

TOTAL E&P Indonésie (TEPI) is the biggest gas producer in Indonesia, who also produces oil. At the time this paper is written, TEPI is operating six Production Sites, two Logistic Bases, seven Drilling Rigs, hundreds of Floating Vessels and thousands of Oil & Gas wells.

Central Processing Area (CPA) is a site that produces oil with some free gas from 555 deltaic multilayer sand reservoirs of Handil field. The site was built 40 years ago with its peak production around 200,000 BPD of oil in 1977. Today CPA produces on average 16,000 B/D of oil and 30 MMsfcd of gas. From total 694 well strings, only about 20% of it is actively flowing; these well strings are spread over 65 clusters. Most of the oil wells are artificially lifted by pump or gas lift compressors.

Facilities were added and adapted along with the needs, such as High and Low Pressure gas compressors and Gas Lift Compression unit. Several Enhanced Oil Recovery (EOR) projects had been tried, such as gas injection, air injection, and water injection. Currently the only artificial lift remaining is gas lift, and the EOR remain is water injection; the rests are stopped and modified.

Nowadays, the main challenges of this mature field are integrity and HSE. Old design, obsolescence, modification of existing facility, and integrating with new technology generates several risks. Along with the maturity, leaks and potential leaks increase over time. The issues are corrosion, surface cracks, seepages, fugitive emission, obsolete equipment, increasing sand production, etc. Furthermore, several disused equipment also become another threat.

This paper will discuss how CPA, a 40 years old Oil & Gas Production Installation, manages its Integrity and HSE. It will explain the challenges, good initiatives, and room for improvements. The topics will include Risk assessment & Identification, Inspection strategy, Integrity, Maintenance, Preservations, Work Permit implementation, Emergency exercise, etc.
Paradigm Shift From Traditional to Modern Drilling Using Simple Management Tool
Authors: Azwar Noezran , Abdila Sayid F. , Fadil M.
Published: October 2015

Objectives/Scope: Reports from a NOC under Production Sharing Contract with SKK Migas show that MDT success ratio conducted is only 40–50% between years 2012 to 2013. High frequency of failures happened in 12 ¼" hole. The objectives of the research are to find out source of the problem and the solution. The scope of the research is MDT procedure conducted in years 2012 – 2013.

Methods, Procedures, Process: Research starts with investigation of years 2012 to 2013 MDT failures. The results then categorized as equipment and tools related, procedures related, and human error. The results show most of failures root-caused by insufficient procedure. Further investigation using interview with engineers and reports examining conducted on the existing procedure. Investigation shows the NOC not conducting proper management of change process to include MDT procedure since they believe existing procedure is adequate for additional MDT work. The research then exercises new drilling procedure using management of change and lean sigma approach. New drilling and MDT procedure then applied to year 2014 campaign.

Results, Observations, Conclusions: In late 2013, SKK Migas enforced the NOC to apply proper drilling procedure for MDT. The NOC used management of change and lean sigma process to design new procedure and included any additional works required. The NOC also used heuristic approach to adapt the lithology character of subsurface formations and aquifers specifically since there was coal layer beneath. The NOC also considered any lesson learn from adjacent well and field. Drilling campaign in 2014 for the field consists of 10 drilling with MDT. New procedure was applied and close monitoring was performed. Nine of ten drilling works with MDT were successfully performed without major incidents. The wells are still producing and showing good production performance. The NOC also successfully uses MDT results from nine wells to predict field performance and planning 2015 drilling campaign.

Novel/Additive Information: Management tools such as management of change process and lean sigma has been applied in many fields of work nowadays. The practices assure that any additional works or changes will be adopted properly and in a new and lean procedure or design. This paper shows radical success ratio increase when those management tools are applied especially for traditional-fashioned NOCs.
Improving Efficiencies of Short Duration Projects During Turnarounds: A Case Study on Innovative Breathing Air Solutions
Authors: Schoeib Sameh , Dowd Darrell , Daher Elie
Published: October 2015

A frequent challenge during facility shutdowns and turnarounds is the congestion of work areas. As a result, carrying out short-duration tasks such as blinding with powering pneumatic tools take much longer time due to equipment transport and set up the process. To respond to this challenge, a portable breathing air delivery unit was designed with a narrow footprint to allow quick and easy deployment even in constricted work areas.

The portable breathing air unit provides ten man-hours of breathing air and can support two users. It has a separate air tool port to power pneumatic tools. A backflow preventer ensures that air tool cannot contaminate the breathing air supply. As a safety measure, the air tool supply shuts down at 1000 psi, leaving the worker with approximately two man-hours of breathing air. To ensure that personnel have the required safety equipment and the ability to complete their assigned jobs, the unit is equipped with a platform to transport required gear to remote work areas.

The portable breathing air unit was recently put to the test by a Gas to Liquids company during its emergency facility turnaround. This is a case study for the use of such system capable of providing both breathing air and power tools in constricted work areas. During a turnaround for example, to remove a set of flange bolts from a pipe, the entire operation may take 10 minutes, but the actual operation of the air wrench may only take two minutes of that time. However, actual job tickets indicate that a 10-minute job takes a minimum of 30 minutes to one hour to complete due to the long process of deploying safety gears, breathing air systems and a separate pneumatic power source. By utilizing this portable breathing air delivery system with a dual purpose, activities such as blinding can be done more efficiently while ensuring personnel safety.

This case study discusses the significance of this innovation in improving efficiencies during turnarounds.
Digital Oilfield Down Under: Implementation of an Integrated Production Monitoring and Management System for the Maari Field, Taranaki, New Zealand
Authors: Marron A. J. , Milner M. , O'Hagan A. , Biniwale S. S. , Trivedi R. , Simpson T. , Tran A. C.
Published: October 2015

The Maari oil field, the first OMV operated offshore oil field development, has showcased OMV's impressive technical skills. Following the completion of a field re-development drilling campaign in August 2015, the well configuration currently consists of 10 producers and 1 water injector (with the option to convert a producer into a water injector in the future). Electric Submersible Pumps (ESPs) are installed on all 10 producing wells to provide lift of reservoir fluids to surface. A SCADA system and associated Production Historian Database (PHD) was included in order to capture the high frequency data for well & reservoir surveillance and daily production optimisation of the field. However, there were many challenges in utilising this live data stream from the offshore facility. In particular, it was vital to continuously and effectively monitor and optimise ESP performance in order to improve run life, reduce downtime and ultimately increase production. An integrated decision support system was therefore required for real-time data collection, production monitoring, ESP health check and KPI analysis for proactive decision making and limiting the number of manual processes involved.

This paper describes how these challenges were overcome by creating an integrated workflow and aligning the existing system architecture in order to meet the business needs. The system is based on full workflow automation, and has been deployed for data acquisition, validation and analysis by optimising the components of integrated asset management. The system includes an integrated framework connected to various live data sources with different time increments, allowing data aggregation to a reliable intra-day hub. Automated job scheduling has also been built in with a decision support dashboard setup for production analysis and ESP performance monitoring. Based on historical trends, an optimum operating envelope was defined and automatic rules were configured for anomaly detection.

The system has provided standardized data access throughout the asset team, streamlining their entire process and resulting in improved efficiency, which has optimised the engineers time for core operational activities. With a secure and automated workflow, and the ability for multiple users to work simultaneously, the system has minimised their downtime, thus improving overall productivity. Utilizing the live data feed for updating of simulation models has allowed quicker comparisons of numerical predictions with analytical forecasts, hence helping to streamline the overall reservoir management of the field. The system has not only assisted the team in meeting their production reporting deadlines, but has also alleviated bottlenecks in their decision-making processes helping to boost overall asset productivity.
Samarang Integrated Operations (IO) – Dynamic Production Management - A Hybrid Approach from Steady State to Transient Modeling
Authors: Izzami M. Hafez , Ahmad Zul Izzi , Sepulveda Willem , Salim Muzahidin Muhamed , Wong Lee Hin , Som M. Kasim , Biniwale Shripad , Rodriguez Nelson , Kumar Ram , Wilson Matthew , Eradajaye Iroro
Published: October 2015

Samarang is a 35-year-old offshore oilfield in Malaysia, operated by PETRONAS Carigali Sdn Bhd (PCSB). Samarang Redevelopment Project was kicked-off in 2010. Integrated Operations (IO) was planned as an Asset Management Decision Support solution by implementing a real time production, reservoir and process surveillance system. Samarang field was the first field selected for end-to-end asset management IO project. The main objective of IO implementation is to focus at the whole asset operation rather than working in silos. The overall asset optimization is achieved through the levels of monitoring and surveillance, diagnosis, optimization and operations transformation.

IO Implementation involves identification of various intelligent asset decision processes referred as workflows in various reservoir, production, and operation domains such as Flow Assurance, Well Performance, Artificial Lift, Production and Facility Planning and Enhanced Oil Recovery (EOR) Optimization. Optimization in Samarang covers a wide spectrum of scenarios from Artificial Lift (Gas Lift, Electric Submersible Pump), separation process, reservoir sweep (Waterflood, GASWAG EOR scheme). The main business driver is to enhance production and improve reserve recovery in order to ramp up the production of Samarang field.

Hybrid Steady-State and Transient-State Total Asset Optimization is designed for implementation through Steady-State model based simulation while the Transient-State model continuously predicts short term transient production effects, as a result asset team can better manage the short term production upset to ensure optimization target is achieved. The transient normally manifests as "Flow Assurance" events such as slugging and surges and these manifestations are to be predicted through transient-state modeling and hence, allow corrective action to be taken through Tri-Node Collaborative Working Environment (CWE).

The hybrid modeling techniques treat the asset as a whole unit instead of isolated silos, simulating the complex interactions between reservoir, production networks and process facilities where decision taken on the production network will propagate the impact to reservoir performance and vice versa.
Rate Transient Analysis in Hydraulic Fractured Tight Gas Reservoir
Authors: Joo Hyeonseog , Ki Seil
Published: October 2015

In order to evaluate development plan of unconventional tight gas reservoir in production stage, Rate Transient Analysis techniques can be utilized to get estimates of OGIP, EUR, SRV, and relevant information, which are based on boundary-dominant flow analysis. In this study, various RTA techniques (Flowing Material Balance, Type Curve Matching, Square Root Time Plot, and Analytical Model Analysis) are carried out to get these estimates and validate results to each others.

Under the condition of the field in this study, about 2.3 years' production data, flow-rate and flowing well-head pressure, micro-seismic, loggings, and relevant data are utilized for analysis of production performance and estimate of OGIP, EUR, and SRV. In the target well of study, boundary dominant flows start after initial 8 months. The various RTA techniques (Flowing Material Balance, Type Curve Matching, and Square Root Time Plot) show consistency of the time for initial boundary dominant flow, and the reliable analytical model analysis result validate estimate of OGIP, EUR, and SRV from the various RTA techniques.

Even though we have reliable well production estimation, there must be uncertainties for pressure depending SRV. By changing the analysis point after those periods, time-depending changes of OGIP, EUR, and SRV can be traced. This trend can provide guidelines for reservoir simulation study and its history matching scheme. In this study, the integrated analysis of RTA and simulation and its results are provided.