bluuebunny/crossref_metadata_2025_split huggingface dataset:
Maximizing More Barrels in Brownfield Rejuvenation through Integrated Collaboration
Authors: Mohd Sharir N. A. , Mohamad Nordin N. F. , Abdul Latif A. H. , Wan Khairul W. M. , Mohamed T. A. , Johar Z. 
Published: October 2017

Abstract
In today's business paradigm, early monetization of resources is a key competitive edge. This requires an effective development plan fostered via sound cost-benefit analysis followed by the systematic and timely implementation of said plan. The drive to obtain faster oil has led to a comprehensive collaboration between PETRONAS and PSC Contractors in one of its biggest oil fields.
Daisy Field is situated 170km off the coast of Terengganu, Malaysia and the first oil was discovered in 1991. The field reached its peak production in 1999 (90,000 bopd) and has undergone steep decline since then, with current average production of ~25,000 bopd. Using extensive historical surveillance and production data, an initiative was taken to identify and unlock remaining reserves.
A new approach to an existing engineering technique called Locating the Remaining Oil (LTRO) has been applied in Daisy Field as an alternative to time consuming static-dynamic modelling. This new approach integrates cased hole log information, production data and decline curve analysis in order to identify bypassed or undrained oil that can be monetized through behind casing or infill drilling.
This paper is a case study on the utilisation of LTRO for brownfield rejuvenation. LTRO is a low-cost but effective solution for idle well reactivation;it may accelerate identification of opportunities, which could be exploitable even during low oil prices, as prevailing currently. Following its deployment within the collaboration, reserves addition has been realized, value created and the cycle time for brown field development plan approval was reduced significantly. This paper will also demonstrate how integrated collaboration between host government, operator and service provider can be a good synergy for effective brownfield rejuvenation.
Drilling Problems Mitigation in Geothermal Environment, Case Studies of Stuck Pipe and Lost Circulation
Authors: Nugroho W. A. , Hermawan S. , Lazuardi B. H. , Mirza R. 
Published: October 2017

Abstract
Geothermal energy is one of fast growing renewables resource in the world. Demand for renewable resources leads to increase of geothermal drilling activities. Well cost contributes up to 40 % of total geothermal project cost. Drilling in geothermal faced many challenges due to its natural characteristics. The most common problems are lost circulation and pipe stuck. Highly fractured zone is the ideal spot for geothermal production. Lost circulation is common in highly fractured formation. Stuck pipe is another problem. Stuck pipe can lead to extra cost of lost-in-hole and fishing operation. Water played an important role in geothermal drilling, not only to keep the wellbore pressure but also to cool down the temperature.
This paper shows some severe cases of lost circulation and pipe stuck in geothermal drilling. All of the data are taken from geothermal drilling projects in Indonesia. The cases of lost circulation can be divided into two major type based on the location, shallow and deep lost circulation. Each has different technique to overcome lost circulation. Two cases in pipe stuck presented in this paper are the most severe incidents in geothermal project in Indonesia. Underbalanced drilling was a common application in highly fractured and subnormal pressured formation as found in geothermal. Both cases performed underbalanced drilling prior to stuck pipe incident. This paper evaluates gas-liquid flow rate based on Guo and Ghalambor (2002) criterion.
Evaluation of Factors Influencing the Effectiveness of Passive and Autonomous Inflow Control Devices
Authors: James E. J. , Hossain M. M. 
Published: October 2017

Abstract
Autonomous Inflow Control Devices (AICDs) are a relatively new technology with the potential to improve the production performance of horizontal wells. The devices control the inflow of reservoir fluid to equalise influx along the length of a horizontal well, and adjust the level of constraint depending on the fluid flowing such that water production is hindered and oil production is promoted. In order to assess the effectiveness of autonomous ICDs compared to passive ICDs, which apply a constant level of restriction, numerical simulations and sensitivity studies were conducted.
A detailed model of the lower completion of a theoretical horizontal well was constructed using an Integrated Production Modelling (IPM) simulator. ICDs were represented using an Inline Programmable Element and equations to calculate the pressure drop of a range of different passive and autonomous ICDs were input. Simulations run on this model allowed the pressure drop across each ICD to be analysed, and the liquid rates at the heel and toe of the well to be compared, to assess how effective the ICDs are in promoting a balanced influx from the reservoir along the entire horizontal length of the well. Oil viscosity, heterogeneous permeability, and oil-water-contact levels were then varied to evaluate the behaviour of the ICDs in different scenarios.
Analysis of the simulation results suggests that none of the tested ICDs are the best performers in every scenario. The Rate Controlled Production (RCP) Valve AICD is the most effective device in heavy oil wells and in wells with uneven oil-water-contacts. The EquiFlow AICD is the optimum performing devicein a reservoir with heterogeneous permeability, and the nozzle ICD is the most effective device in light oil wells. Comparative study of the behaviour of passive vs autonomous ICDs indicates that there is a difference in performance between these two types of ICDs. In some cases autonomous ICDs can provide significant benefits, where as in others the passive ICDs are just as effective.
Successful Application of Expandable Liner Hanger in HT Sidetracking Well Completion: A Case Study in Liaohe Oilfield, China
Authors: Huang Shouzhi , Chen Qiang , Han Weiye , Li Tao , Ming Eryang , Sun Qiang 
Published: October 2017

Abstract
There are a number of challenges existing in conventional slip-type liner hanger, such as undersealing annular of overlapping liner, limited high temperature resistant performance, et al. With the development and improvement of expandable tubular technology, expandable liner hanger (ELH) is developed to replace the current hanger and external packer completely, aiming at the shortcomings of the conventional liner hanger. ELH can isolate packer liner and the main casing, replace the conventional cement sealing way, and reduce the overlap length.
Here a new thermostable ELH was developed to apply in HT sidetracking well completion. The length of annular seal section of ELH is short but reliable, and maximum sealing pressure reaches 35 MPa. According to the requirements of the drilling process, tool string can be lifted, lowered, rotated and circulated to ensure extension liner string down to the bottom and improve the quality of liner cementing. The construction process is simple with low pressure, reliable operation and long service life after the production. The ELH has large bore size, larger than conventional casing under the hanger, in order to run in oil pump through the extension liner string. So the running in depth of pump is not affected by hanger diameter that can improve oil recovery ratio. The metal sealing is used in ELH for heavy oil thermal recovery wells, and it can be used under highest temperature of 300 C. This ELH tool string can fulfill tool setting and bottom sub salvage at one trip. The annular seal pressure of ELH is more than 35 MPa, construction pressure is 25 to 35 MPa, and suspension force is 600 kN.
This new ELH technology has been applied in HT sidetracking well completion in Liaohe oilfield. The hanger position is from 1491 m to 1493 m, inclination is 89 degree, the length of overlapping section in casing is 33 m, the length of sieve tube is 204 m, the length of blank casing is 55 m, and total length is 259 m. The running in depth of sieve tube guide shoe is 1753 m. Lift string suspending weight is 32 tons. ELH suspension was successful.
This paper provides a solution to HT sidetracking well completion using thermostable ELH technology. And the experience of operation process was shared in this case to be helpful for technology applications in similar situations.
Transient Thermal Model of Drilling Fluid in Wellbore under the Effect of Permafrost Thaw during Drilling in Arctic Region
Authors: Xuerui Wang , Baojiang Sun , Zhiyuan Wang , Yang Zhao , Jintang Wang , Zhennan Zhang , Gao Yonghai 
Published: October 2017

Abstract
The arctic could hold about 30% of the world's undiscovered gas and 13% of the world's undiscovered oil according to an assessment by the United States Geological Survey (USGS). While, arctic oil and gas exploration is faced with various challenges such as the extremely cold polar environment, the ice scour, the permafrost. Permafrost is the perennially freezing soil (actually freezing pore water), and it can be an important geologic hazard and constraint. Permafrost is very common in arctic region, about one-half of the total land area of Canada and Russia and 85% of Alaska is underlain by permafrost. Besides, sub-bottom permafrost is also wide spread phenomenon of Arctic offshore areas.
At present, the traditional thermal models of wellbore use an algebraic approximation to describe the heat transfer between wellbore and formation. Thus a new model should be established considering the effect of permafrost thaw during drilling in arctic region. As a matter of fact, the phase change of ice in permafrost needs to absorb heat from wellbore which can have an effect on the wellbore temperature. At the same time, migration of water from warm to cold regions will happen during the process of the thaw of permafrost. The migration of water will have an effect on the temperature due to the heat transfer along with the water. In addition, temperature in wellbore can be negative after long shut-in time due to the extremely cold polar environment which could lead to the blocking of wellbore.
In this paper, a transient thermal model of wellbore during arctic drilling is established considering the effect of permafrost thaw in this paper. On the basis of the new model, a simulation of an arctic well is made and some conclusion are made from the case study: The temperature fields in wellbore and permafrost interact with each other. Besides, the temperature in wellbore drops to negative due to the extremely cold environment after long shut-in time, and the drilling fluid in wellbore could be frozen consequently. Long shut-in time should be avoided during drilling in arctic region.
The new model established in this paper can determine more reasonably the wellbore temperature in artic permafrost region than the traditional model. A method to determine the reasonable shut-in time is given in this paper which can provide safety guidance during drilling in arctic permafrost region.
Integrated Portfolio Analysis of Gas Field Clusters: How to Make Fast, Yet Informed Decisions
Authors: Kumar Gyanendra , Bezemer Taco Den , Chima Chima , Dewil Stoffel , Trivedi Bhaskar 
Published: October 2017

Abstract
Key project decisions like field sequencing, plateau size, and design back pressures in a green gas field cluster development require a robust integrated system modelling. Given that most project decisions are made in economics domain, it is crucial to include the project economics within the integrated system modelling suite. This paper describes application of a workflow which integrates the subsurface, surface, costing and economics evaluation within the ambit of a single integrated modelling tool.
Typically network models are computationally intensive and project teams will only run them for few deterministic cases. The probabilistic analysis is performed at reservoir/field level, and they are combined to define deterministic (Low, Mid, High) case network models. However, this approach poorly captures surface-subsurface interactions and doesn't provide full solution space at the network level. Furthermore, to generate development options and scenarios, typically oversimplistic subsurface models are used that do not sufficiently capture liquid yield over time and water encroachment.
The proposed workflow does probabilistic simulations at network level to capture the full solution space. The workflow allows representation of project decisions and uncertainties under the same platform. Furthermore, representative modelling of reservoir architecture and fluid fractional flow allows more accurate prediction of liquid hydrocarbon and water which helps in robust facility design. Semi-automated nature of the toolkit allows generation of project economics for large number of sensitivities and scenarios in quick time. This approach is very useful where with only basic information fast analysis is required to start commercial negotiations, and in situations where good statistical coverage is more important than very detailed outcomes (even when detailed information is available) to support decsions.
Managing Offshore Oil Field to Enhance Ultimate Recovery in Asri Basin, Southeast Sumatera, Indonesia
Authors: Waskito L. B. , Widiatmo R. , Afi F. N. 
Published: October 2017

Abstract
This paper covered success collaboration between sub-surface and surface engineer in managing mature offshore oil field in Asri basin, Southeast Sumatera, Indonesia. The main objective was to maintain oil production rate and increase ultimate recovery in the most efficient way, technologies that applied strictly selective to minimize risk while optimize oil production. Common problem faced are extremely high water cut and high operating cost due to massive artificial lift application.
The three effective tailored methods in this paper are: (1) Determining residual oil volume and locating the position. Material balanced calculation and core analysis are the tools to determining residual oil volume, while tracer test conducted in order to determine the location and distribution of the oil remained. (2) Surface facilities assessment, facilities are ageing and need to refurbished/replaced after 27 years of production, it creates limitation in operation area. (3) Potency screening, in this phase we focused more on technical difficulties assessment, both sub-surface and surface (from method 1 and 2) result analysis are combined to determined technology selection. After that we put into action, and do evaluation on cost spending and production performance.
Efficiency is the key issue in mature field redevelopment, solid collaboration between sub-surface and surface team lead to satisfying result to reduce production decline. Several case studies have been included in the paper to highlight the detail project: (1) Idle wells, to increase production it is very important to increase well count, the wise way is by utilize existing wells in idle condition. Mechanical failure, water out, formation damage, low potential, etc. are cause of idle wells, in the last 3 years 13 wells successfully back to production. (2) Modified completion fluid, one of technology applications with ‘breakthrough’ result. In depletion drive reservoir we found lot of residual oil potency that can't be sweep, the solution is to reduce oil viscosity around wellbore and increase the mobility using modified completion fluid, and the result is beyond expectation. (3) Water injection redirection, based on performance evaluation and tracer injection analysis, several injectors is ineffective due to reservoir connectivity and mechanical issue, this project creates new sweep pattern and successfully increase recovery factor. (4) Mechanical loss handling, we found big losses contribution from tubing leak, after laboratory and field analysis losses can be reduced.
Technology and integration of sub-surface and surface capabilities are vital to unlocking the full potential of mature assets and achieving higher recovery factors. Application of the three tailored methods was considered as an appropriate way to approach and manage a complex mature field redevelopment.
Oilfield Microbiology: Effective Evaluation of Biocide Chemicals
Authors: Bennet Douglas 
Published: October 2017

Abstract
"Kills 99.9% of bacteria". Sounds impressive. Consumers will have seen this claim on supermarket shelves on all kinds of household biocide chemicals such as hand soaps and detergents. In reality, what does this actually mean? Is a kill target of 99.9% an effective biocide? On the face of it, it sounds very good. However, when referring to microbiological populations, like bacteria, this requires context. What was the original number that was reduced by 99.9%? When quantifying microbiological populations, it is common to use extremely large numbers, referenced in logarithms (1.0 × 105 or 1.0 × 106 cells).
Reducing bacterial populations by 100% using batch dosed biocide chemicals is an impossible feat. It will never be possible to entirely eliminate 100% of bacterial populations, as some will always survive and potentially recover to pre-dose populations. Therefore, selection of the most efficient biocide chemical is of the utmost importance.
In the example scenario of a hand soap, the target of 99.9% is very difficult to achieve. The biocide chemical is applied to the target surface area (hand) and almost immediately diluted and washed off by a running stream of water. The chemical might get a contact time of up to 1 minute to kill 99.9% of bacteria under normal circumstances.
Although hand soap is not directly related to control of bacterial populations in oilfield process systems, the theories behind the testing of all biocide chemicals are the same. It boils down to three parameters that need to be tested; chemical, concentration and contact time, tested against microbiological populations. The questions any operator should ask before using a biocide chemical should be; Which biocide chemical?What concentration should be applied?How long should the biocide chemical be added for?
By answering these questions, the operator will have learned key points as to the efficiency of the biocide chemicals under test in relation to the required conditions.
This paper will discuss a recent example of a biocide chemical evaluation carried out by a Malaysian operator, in which fourteen different biocide chemicals were tested to determine the most efficient biocide chemical. Each biocide chemical was tested under controlled laboratory conditions against both planktonic and sessile mixed microbial consortia populations, and ranked for efficacy.
Field Test Results in Malaysia Wells of a New-Generation Slim Pulsed Neutron Logging Tool
Authors: Millot P. , Wong F. K. , Rose D. A. , Zhou T. , Grover R. , Sundaralingam S. , Amin F. , Prasodjo A. , Johare Dzulfadly , Kwang Hui Nicholas Foo 
Published: October 2017

Abstract
Pulsed neutron spectroscopy (PNS) is a well-established technology for characterizing reservoir saturation through cased hole, using either sigma (Σ) or carbon/oxygen (C/O) ratio measurements. However, the current technologies struggle to deliver reliable answers in complex completions. Tubing and casing, with varying tubing and annulus fluids, or dual tubing completions with changing annulus and tubing fluids represent cases in which it becomes difficult to identify fluid contacts in the formation and calculate remaining saturations.
A new-generation slim pulsed neutron logging tool has been developed to deliver reliable answers in conditions that challenged existing technologies. It introduces the new petrophysical measurement, fast neutron crosssection. This measurement is highly sensitive to variations in gas volume and insensitive to variations in water volume, independent of neutron porosity and formation Σ properties. It provides high-resolution spectroscopy with a much-improved accuracy and precision of all elements measured, including the key element for oil saturation, carbon. The carbon measurement is used conventionally for C/O, and it is used directly to derive total organic carbon (TOC), which is then converted to oil saturation.
This tool delivers the self-compensated Σ and neutron porosity measurements in a wide range of conditions, including complex completions and varying amount of gas in the wellbore or annulus.
The field test results in this paper demonstrate the performance of this new tool in a few wells from Malaysia. All present some complex completions, from single tubing inside 7-in. casing and 8.5-in. hole to dual 3.5-in. tubing in 95/8-in. casing and 12 ¼-in. hole. Additional challenges include gas-filled annulus, multizone completion with sliding side doors (SSD) and wire-wrapped screens (WWS), and environments in which there are no water sands for C/O measurement calibration.
The logging objectives include determining theoil/water contact (OWC) and the gas/water contact (GWC),quantifying the current saturation, confirming the source of water for water shutoff determination and anticipated gain, and verifying sand-filled annulus. A back-to-back comparison with the previous technology was also run in the first well, allowing a directcomparison of the measurements from the new and the existing tools in the same conditions.
A Case Study of Shallow Water Flexible Pipe Project Execution for Maintaining Production in Marginal Field, Offshore North West Java Indonesia
Authors: Sinulingga E , Yananto H 
Published: October 2017

Abstract
An offshore well-platform namely "xyz" is in a marginal gas field operated by Pertamina Hulu Energi Offshore North West Java (PHE ONWJ). "xyz" production is transported to the "xy" platform via a 6.3 km 8" Main Gas Line (MGL), which has been in operation since 2002. In 2015 several leaks were detected and it was known that well ‘xyz-1’ produced high CO2. A Repair by conventional means i.e. replacement with the same steel material was deemed uneconomic due to the high CO2 content. A study was therefore initiated to evaluate the technical and economic feasibility of low capital cost and low maintenance cost technologies to rehabilitate pipelines in marginal fields with high CO2 content without increasing safety or environmental risks.
In the appraisal stage, several technology options were considered and a thermoplastic pipe was selected as the preferred alternative compared to traditional rigid carbon steel pipeline. The assessment process started with a pipeline technology review, followed by technical compatibility/acceptance study, a check of commercially available pipe sizes and a comparison of total installation cost, installation schedule, and operation-maintenance considerations. The decision was facilitated by Expected Value Decision Analysis. The expected value of each option included CAPEX, OPEX, NPV, and all quantified aspects and risk.
The thermoplastic plastic pipe assessed is a flexible pipe for shallow water consisting of polyethylene (PE) internal liner, annular ring steel strip armor, and PE outer sheet. The PE inner liner is nearly hermetic, but allows traces of gases such as CH4, CO2, H2S, and H2O to permeate through. These permeants tend to accumulate in the flexible pipe annulus. A slight overpressure above atmospheric develops in the pipe annulus driving the gases to the end fittings where they are vented, preventing excessive pressure build up.
Additional weight is required for on bottom stability of thermoplastic pipe to be laid in Offshore North-West Java area. The installation spread was using the available Pipe Lay Barge blanket contract for the Pipeline Repair and Replacement Program. Even though different technical approach needed to accomplish the work, such as the need of additional weight and using lay barge instead of DP2, the selected concept is still the most economic compared to other options. The CAPEX spending was competitive compared to carbon steel pipe one. In addition, OPEX reductions can be achieved by reducing pigging operations and eliminating In-line Inspection (ILI) and chemical injection.