bluuebunny/crossref_metadata_2025_split huggingface dataset:
Ultra-Low-Invasion Fluid Technology Increases Operational Window to Enhance Drilling, Reduce Damage in Unstable Venezuela Formations
Authors: Herdes Miguel , Aguilar Katiuska , Fernandez Daniel , Garcia Jose , Moreno Jose , Maldonado Reinaldo 
Published: October 2017

Abstract
Historically, the well documented diversity and complexity of formations throughout Venezuela have severely complicated the design and engineering of drilling fluid systems capable of maintaining the wellbore stability required to maximize drilling efficiency and reduce formation damage. Producing formations in Eastern Venezuela, are typically low-pressure consolidated sands with elevated bottomhole temperatures and differential pressures ranging from 3,000 and 7,000 psi.
This paper describes the technical development and subsequent application of an ultra-low-invasion drilling fluid additive, designed to deposit a thin, impermeable barrier over the pores and microfractures of weak, under-pressured and otherwise troublesome formations, to maintain wellbore stability and reduce formation damage. Three case studies will be presented to demonstrate the effectiveness of the technology to prevent differential sticking and other wellbore instability issues, minimize fluid-related non-productive time (NPT), increase overall drilling efficiency, and reduce operating costs.
Validated in 14 wells, the operating window of the Naricual Formation was expanded appreciably due to the use of the ultra-low-invasion drilling fluid technology. It was also demonstrated that stability was maintained in the open hole with 7,000 psi of differential pressure at 16,810 ft, which allowed an optimized well design that eliminated one casing section. The wellbore stability was confirmed with wireline pressure-point log measurements. Furthermore, through direct offset comparisons, the authors will detail significant improvements in wellbore stability and the subsequent prevention of losses and differential sticking in a different field, where more than 1,000 bbl of losses had been recorded across the Miocene and mid-Eocene sediments.
Moreover, core tests results will illustrate the efficiency of the thin, but tough filter cake, to prevent the invasion of drilling fluid into the formation matrix, thereby minimizing formation damage down to 4.5% (95.5% retained permeability). Thus, the original structure of the formation is preserved, effectively preventing formation collapse, differential pressure-induced crossflow across open zones, and importantly, pay zone contamination.
Centrifugal Pump and Centrifugal Compressor Process Containment
Authors: Muthanandan Sundralingam 
Published: October 2017

Abstract
Centrifugal Pumps and Centrifugal Compressorsare classified as driven equipment which are widely used in the oil and gas industry. They are primarily used to boost the operating pressure and transfer liquid and gas respectively in a safe and reliable manner. Process containment is one of technical integrity and safety barrier classified under Safety Critical Element (SCE). Various components such as casing, gaskets and mechanical seals and dry gas seal were discussed, threats and possible damage mechanism and improvements were shared.
Basically, the mechanical seal by design is not a positivesealing like static flangetoflange connection, but rather has always had some acceptable leakage. The question of "how much leak is acceptable" was tested at site, the results analyzed and compared for safe operation. Leading damaged mechanism such as presence of liquid in the DGS in centrifugal compressor application were also discussed.
Lessons learnt related to early failures due to seal, seal cooling system, maintenance practices for correct seal installation post repair works were discussed. Besides that, damage mechanism from the contaminants such as sand in the product and damages tocasing and seals due to erosion and impingement were also discussed. Condition monitoring techniques that can be employed for reliable operation of the pump and compressor seals were also discussed. The article also describe some of the best practices that could improve the reliability of seals.
Low pH and Salinity Induced Wettability Modification of Hybrid EOR as Polymer-Assisted Carbonated Low Salinity Waterflood in Calcite Cemented Sandstone Reservoir
Authors: Lee Ji Ho , Kim Gwan-woo , Lee Kun Sang 
Published: October 2017

Abstract
Hybrid polymer-assisted carbonated low salinity waterflood (PCLSWF) modifies both oil and brine viscosities and wettability in calcite-cemented sandstone reservoirs. In core- and pilot-scaled systems, PCLSWF increases ion-exchange of Ca2+ modifying reservoir wettability toward to water-wet condition. In the process, dissolved CO2 in brine is transferred into oil. The interphase transport reduces both oil viscosity and density. As well, the dissolved CO2 in brine reacts with water and produces H+ in brine. This low pH of PCLSWF dissolves calcite minerals and provides Ca2+ into brine resulting in increased ion-exchange of Ca2+. Due to significant mineral reaction rate in pilot-scaled system, enhanced wettability modification by mineral dissolution is observed in pilot-scaled system rather than core-scaled system. In addition, PCLSWF increases the viscosity of displacing fluid. Though it undergoes mechanical degradation and slight chemical degradation, it is still effective to improve mobility. The improved sweep efficiency of PCLSWF allows injecting fluid to flow in less permeable area. In heterogeneous pilot-scaled reservoir, the combined effects of PCLSWF enhance oil recovery up to 12%, 6%, and 2% over low salinity waterflood (LSWF), low salinity polymer flood (LSPF), and carbonated low salinity waterflood (CLSWF). Optimization process maximizes the efficiency of PCLSWF and has recommended to deploy PCLSWF with CLSWF preflush. The optimized injection design of PCLSWF increases NPV up to 18% more than LSWF.
Predicting Start-Up Liquid Loading in a Mature Oil & Gas Field: A Case Study
Authors: Malik Ankit , Prakash Ravi , Kumar Mukesh , Barot Miten 
Published: October 2017

Abstract
Liquid loading of oil and gas wells occurs when the reservoir fails to deliver hydrocarbons to the surface due to accumulation of liquid in the well. In Oil reservoirs with gas cap and aquifer, liquid loading post shutdown revival of oil wells with high gas liquid ratio (GLR) is poorly understood and documented. The mechanism and prediction of onset of such liquid loading has been studied and discussed in this paper.
The field observation of loading of high GLR oil wells could not be explained with steady state analysis in a mature carbonate offshore field. Transient analysis successfully revealed liquid loading as observed in field. However, correct set up of initial conditions is imperative for prediction using transient analysis method which is discussed in this paper. A workflow has been developed to predict onset of start-up liquid loading and to build in risking using a risk matrix incorporating relevant well parameters. The methodology was used to estimate the gas lift requirement and associated risked reserves.
The liquid loading of high GLR oil wells after a brief period of shutdown has been successfully modelled using transient method by representing correct initial conditions. However, ability of well to re-deliver gas at the steady state GLR value during the start-up is an uncertainty. Hence, an element of risking has been captured to predict the most likely time of start-up loading using a risking criterion based on individual well's flow parameters.
The results from the above methodology of prediction and risking show that wells are susceptible to liquid loading much in advance as predicted from steady state workflows which matches with the field observed well performance. This has a significant impact on the lift gas flowrate and top side infrastructure required to sustain flow from these wells. The paper also discusses a strong business case to evaluate liquid loading from predicted parameters at field development planning stage using the proposed workflow to secure future well production and save on additional costs of retrofitting gas lift infrastructure.
Small is Beautiful: Why Small Fields are the Next Big Thing in South East Asia and How to Capitalise on Them
Authors: Volkenborn Arnold , Lea-Cox Andrew , Sun Bo 
Published: October 2017

Abstract
Since the 1990s, most countries in SE Asia have been challenged to meet domestic demand using their own petroleum resources. To date, most easy-to-produce resources have been developed, leaving SEA with dwindling reserves and more technically challenged resources in small/marginal and deepwater fields. The average size of discoveries in SEA has decreased to ~35 MMBOE from double or triple that in the 1970s-1990s. Conventionally, small fields (&lt;100 MMBOE reserves) are riddled with operational and economic challenges. The low oil price environment further exacerbates the resulting poor margins. Exploration and production (E&P) companies have been cutting spending and refocussing their portfolios on core areas of advantage.
In these increasingly challenging & uncertain times for the industry, we show how a new approach to small fields could unlock more than twice the NPV of larger conventional fields in SEA for a similar size of capital expenditure (capex).
Capturing this value though, will require a fundamental step change in operating model of operators. The Small Fields approach focuses on margin maximisation, instead of recovery and productivity maximisation. This means (1) targeting easy sweet spots (at the play and reservoir level); (2) establishing a blowdown-style investment baseline; and (3) selectively investing in incremental projects against this baseline.
Players who adopt this strategy will need to be lean, fast & agile, with an organisation and commercial construct that may more closely resemble a technology start-up than an E&P company. This will be a radical shift in mindset for most E&P companies and especially for National Oil Companies (NOC). But for many Asian countries, this may be the only option to maximise the returns and economic benefits from their hydrocarbon resources before it’s too late.
Advantages of Insert Pump Application through Tubing in SF Field Shallow Reservoir
Authors: Astuti Helmy Rina , Ernata Wayan Mahendra , Prasetya Afriandi Eka 
Published: October 2017

Abstract
"D" Oil fields is one of the largest operating steam flood injection in the world, Steam Flood "SF" project, to pump heavy oil from the relatively shallow reservoir. "SF"s peak production ever recorded at 2 Billion BPD in year 2006. SF project has 13 areas with over 5,000 oil wells production using artificial lift system. Nowadays, SF oil was declining due to natural processes so it will produce less than its peak production.
SF Area were commonly use Subsurface Rod Pump Manifold Tubing Pump, the pump unit as a whole system were set with tubing into the well, where the barrel attached to the lower end of the tubing, and the plunger along with traveling valve is connected in lower end of the sucker rod string. When the pump be pulled then both the rod and tubing should be pulled together. Tubing pump are usually easier to be applied for shallow wells with small productivity.
Currently in SF operates well producers using regular Tubing Pump where only less than 30% of them being produced with optimum fillage and most of them (60%) categorized as low fillage. The low fillage wells are potentially increase with increasing number of well with low productivity (matured Area). Management captured one of alternatives in order to improve number of optimum fillage wells and to increase the pump efficiency by utilizing Insert Pump (not familiar in SF) which is expected have some benefits for low rate wells (below +/-400 BFPD). Which from other project have successfully trial and proven delivered with 10 wells exceeded the previous life span, improved pump efficiency to 37% and reduce &gt;20% RS job cycle time which contribute around 3.7 $MM.
Novelty, the success ratio of using the insert pump was proven by increasing pump efficiency up to 37%; life span of pump unit much longer than usual; Reduce OPEX and increase production by minimizing Loss Production Oil.
An Effective Method in Determining Pore Pressure by Controlling Bottomhole Pressure While Drilling Narrow Window Wells in the Gulf of Thailand
Authors: Rubianto Irwan , Prasetia Andi Eka , Detrizio Pasquale , Charnvit Kerati , Srisai Wanchana , Follett Meth , Dejdamrongpreecha Warapong , Kudisri Rapee , Meghnani Manoj , Loux Fabrice , Phonpuntin Visarut , Eawprasert Somphop 
Published: October 2017

Abstract
Drilling narrow window wells conventionally have been well known to cause major wellbore issues to the Operator in the Gulf of Thailand. Therefore, managed pressure drilling (MPD) has been deployed since several years ago to mitigate the drilling problems. To ensure safety and optimize drilling time, it is necessary to identify the actual pore pressure while drilling wells with narrow marginin order to eliminate kick, ballooning and loss events.
The use of automated MPD system to precisely control bottomhole pressure (BHP) during connections combined withthe evaluation of bottom up gas trend while drilling enabled the pore pressure to be predicted accurately in almost real-time condition without the need to stop drilling in the Gulf of Thailand. Thus, the narrow window wells were drilled faster with MPD, which was beneficial for the Operator in the area where the fast factory drilling was necessary to make wells more economical. Furthermore, the use of this new method in effectively determining the actualpore pressure provided solutions to the Operator in mitigating wellbore issues at the same time improving drilling timeafter several years of MPD technology implementations. The estimated pore pressure results acquired with the new methodon several narrow window wells were even comparable to the actual wireline logging measurement results.
The objective of this paper is to introduce an effective and efficient method in determining pore pressure (PP) while drilling challenging wells with tight reservoir characteristic by utilizing MPD technology in the Gulf of Thailand. In addition, this paper also describes the drilling strategy, detail procedure and lesson learnedin verifying pore pressure with the new method.
Reservoir Damage Removal by Zero-Cost Hydraulic Fracturing in a Water Injector, Offshore Vietnam
Authors: Huy Vu Huu , Sutherland John , Thuy Pham Thi 
Published: October 2017

Abstract
In Te Giac Trang oil field, wells are completed with monobore design and with thru-tubing perforation carried out offline following the well completion phase. Producers in the field are perforated with underbalanced conditions through gas-lift application, which has resulted in relatively low-skin completions. In 2014 the first water injector was drilled in the field, with the same completion design applied as for the producers, however with no gas lift mandrels and surface gas lift line installed for cost saving. As a result, perforation of the injector was carried out without underbalanced conditions. The well started injection in November 2014 at 4k bwpd, with the bottom-hole injection pressure (BHIP) kept below the formation fracture pressure (FFP). Injection performance was below expectation, therefore in November 2015 re-/extended-perforation of key sand layers was carried out in order to increase the injection rate. Well injectivity however significantly reduced immediately following the re-/extended-perforation.
Pressure fall-off (PFO) tests were carried out on the injector, indicating significant near-wellbore damage following the re-perforation. Skin factor increased from +14 before the re-/extended-perforation to +50 afterwards. Impairment of the well injectivity was expected to be due to debris plugging the perforation tunnels. After thorough review of the options for remedial treatment, it was proposed to hydraulically fracture the formation using the existing water injection system. The objective of this treatment was to create and keep fractures open over a period of time, so that debris in the perforation tunnels could be pushed far away into the formation.
The treatment was carried out in February 2016, during which the water injection rate was increased to 12k bwpd, with BHIP significantly higher than FFP, and maintained at this over 3 days. PFO testing following the treatment indicated successful damage removal, with skin factor reduced to + 10. Subsequent well injection rate has been stable at 8k bwpd, with BHIP lower than FFP.
This paper describes the process of injection well performance evaluation, including PFO testing, acquiring reliable FFP, and application of remedial treatment through proppant-free hydraulic fracturing. The paper also covers the lessons learned on the design phase of injection well completion, on perforating and on the capacity of the water injection facility.
Bekapai 2B Brownfield Modification Project: Challenges, Execution Strategy and Lesson Learned
Authors: Budiarko A , Setyawan H 
Published: October 2017

Abstract
Bekapai, the oldest offshore field in Total E&P Indonesie, is a mature oil and gas field located in the offshore Mahakam Delta, Indonesia and discovered in April 1972. All Bekapai production is transferred to offshore Bekapai process facilities to separate and treat liquids and gas before sending them to the onshore processing centre in Senipah. Bekapai Redevelopment Phase 2B Project ("the Project"), a brown field project, is aimed to modify 5 offshore platforms (BG, BL, BA, PP, and SWPK) and debottleneck Bekapai field export capacity by installing new 12" subsea pipeline which will interconnect Bekapai and Peciko Field. The Project presents significant challenges in term of technical, cost, and schedule. It needs to be delivered within 15 months after FID (Final Investment Decision). Hence, the Project is the fastest and biggest offshore brown field modification done by Total E&P Indonesie.
This paper will describe the technical, cost, and schedule challenges of the Project and how the PMT (Project Management Team) dealt with them without compromising safety, especially in avoiding schedule and cost slippage, the two aspects often found in projects and even worse for the brown field ones.
Managing Risks in Relief Well Operations: From Planning to Execution
Authors: Poedjono B. , Macresy L. , Sikal A. 
Published: October 2017

Abstract
The complexity of drilling a relief well requires a robust workflow, which defines all actions to be undertaken at each phase. This workflow is used for decision making at every organization level from the field level to management.
To ensure successful execution, all risks must be identified, and detailed preventive and mitigation actions put in place. These actions reduce risk to an acceptable and reasonably practical level at all times.
The relief well drilling process needs to be consistent and must contain these key elements: A multidisciplinary team with clearly defined roles and responsibilities at each operations step for optimal communication.A thorough understanding of relief well techniques, methodologies, and processes, including various solutions. These solutions must be confirmed with simulation, communication techniques, well control and fluid dynamic killing modelling, relative positioning with various measurements and their uncertainties, and drilling in presence of magnetic interference.All team members and third parties should use drilling simulations during the planning phase to identify any gaps, and ensure redundancies are in place. Scenario planning will ease the go/no-go decision making during execution.Incorporating existing workflows into the entire relief well process, such as anticollision risk management and hazard and risk control, to reduce the risk of having multiple sidetracks or having to drill an additional relief well.
This paper will present the relief well workflow process and provide insight into the seven phases of the workflow, including planning, approach target, locate target, follow target, intercept target, killing operations, and plug and abandon operations.
Sisi Nubi Dashboard: Implementation of Business Intelligence in Reservoir Modelling & Synthesis: Managing Big Data and Streamline the Decision Making Process
Authors: Sukapradja Aldyth , Clark Jesse , Hermawan Hermawan , Tjiptowiyono Soegianto 
Published: October 2017

Abstract
Sisi and Nubi (SNB) fields are two adjacent primarily gas fields located 25 km offshore from the modern Mahakam delta These fields are complex from a reservoir management point of view with hundred thousands of Static & dynamic data, and continuously increase by time. Reservoir synthesis and geomodel update are always on-going process with numerous QC, data mining & data manipulation. In brief, Sisi Nubi data management & synthesis challenges are: (1) Enormous size of static & dynamic data (2) Numerous Data mining & data manipulation (3) Rigorous Geomodel QC and reporting.
Business Intelligence (BI) is the philosophy of this study; it is a set of techniques and tools for the acquisition and transformation of raw data into meaningful and useful information for business analysis purposes. The goal of BI is to allow for the easy interpretation of these large volumes of data.
The Sisi Nubi dashboard is a self-service business intelligence tool that was design by the asset to answer & streamline the database management and reporting, hence give more time for the asset's geosciences team to do the reservoir synthesis and optimize the study time by automate the data mining & manipulations. The Sisi Nubi dashboards composed of an automated workflow in the geomodeling platform for the data mining, combined with spreadsheet based tool for the data manipulation and presentation (dashboard-ing).
The result of this study presented in 6 unique dashboards, representing 6 difference perspectives of the user. These dashboards are linked to the SNB geomodel and allow instantenous update. Combined with the updated SNB geomodel workflow, the collaboration of two tools has proven significantly streamline the geomodeling reporting & synthesis efficiency.