bluuebunny/crossref_metadata_2025_split huggingface dataset:
Perched-Water, the Concept and its Effects on Exploration and Field Development Plans in Sandstone and Carbonate Reservoirs
Authors: Gaafar Gamal R , Altunbay Michael M. , Aziz Shaharudin B A 
Published: March 2016

Abstract
Perched-water conditions have been observed infrequently in oil and gas fields in zones above fine-grained material that may be located a few to 100 meters above the oil water contacts. Although infrequent in scale of number of fields globally, perched-water zones are important consideration when evaluating reserves and planning field development. The study described in this paper was conducted to examine perched-water conditions and quantitatively evaluate factors that control perching behavior and its impact on field development plans.
The differences between perched-water and hydrodynamically-tilted contacts have to be understood and clearly identified in a given reservoir by studying geological controls. The geological controls that shape contacts either perched or hydrodynamically tilted do play vital role in field development plans because of their structural differences leading to pressure communication or the lack of it. A perched-water zone in subsurface is defined as a water-saturated zone that is above contact or as a water-saturated zone not-directly-connected to the regional oil-water contact. Perching phenomena may occur in a permeable layer overlaying a relatively impermeable layer and conditions that could force water to infiltrate vertically through low permeability layer.
The stress conditions that lead to formation of perched-water are extraneous. However, petrophysical properties of the subject rock that is exposed to the prevalent conditions determine the viability of formation of a perched-water structure. Hence, neither structural geology, stratigraphy and depositional environment studies nor facies and petrophysical evaluations can be performed alone to decipher if a structure is/can be considered "perched-water". Therefore, the cases evaluated in this study are interrogated from structural, hydrodynamic and petrophysical perspectives to decide if subject structures can be deemed to contain "perched-water". The correct diagnostic brings additional hydrocarbon pore volumes or cost savings when drilling below apparent hydrocarbon-water contacts with misconception of a probable perched-water both affecting the financial positively
First Remedial Sand Control Treatment Case Study from Sumandak Field in Malaysia
Authors: Samvelova Marina , Priatna Oktaf , Kristanto Tutus , Thian Kelvin , Rosland Eadie Azahar B , Sandanasamy Ronfernandez , Tashkenbaev Timur , Kwang Hui Nicholas Foo , Rechoum Hassan , Fraser Mark 
Published: March 2016

Abstract
The Sumandak field is located offshore Sabah, northwest of Labuan Island, in Malaysia. The majority of the reservoirs in this field are oil producers subject to sand production at some point during well life.
The subject well was completed using a typical completion design for the current field, running standalone screens inside an 8.5-in. open hole using 3.5-in. dual and monobore production tubing strings. Several wells in the study field are shut in and not producing because of the significant amount of sand and fines produced to surface facilities and filling the tubing, thus negatively affecting production. To reactivate the wells, remedial sand control techniques were necessary to restore productivity of the reservoir.
This paper presents a through-tubing recompletion method combining mechanical techniques, such as a through-tubing intervention approach, along with downhole equipment and a chemical approach that used a fines control treatment, which helped bond the formation fines in place to assist with restoring initial cementation of the reservoir and reduced the risk of blocking the screen media.
The success of this operation was aided by an intensive laboratory study of cores from the field to optimize the design of the tool assembly and treatment formulation based on the particle size distribution (PSD) profile and production histories from the described wells.
Through-tubing downhole tools were chosen considering tubing and casing sizes, the wellbore minimum restriction, type and locations of the landing nipples, reservoir properties, bottomhole pressures, packer setting depth, length of the reservoir to be recompleted, location of the interval in relation to production tubing, length of the rat hole below the interval, and consideration to repair an existing but possibly damaged standalone screen. An advanced wellbore-cleanout technique for low bottomhole pressure reservoirs that uses an upper jet and washdown jet nozzles in conjunction with coiled tubing (CT) was performed before the consolidation treatment.
This is the first time a through tubing recompletion of the existing wellbores has been implemented in the Sumandak field in offshore Malaysia. This methodology has integrated new and existing technologies to achieve successful sand control operations to bring a well back on production after having been shut in because of sand production. It helped reactivate the wells and improve the recovery reserve rate of the field.
After this successful treatment, productivity of the well has exceeded expectations compared to conventional gravel packed wells. Such placement techniques created many opportunities to effectively and economically treat and revive wells experiencing similar production issues.
A Streamlined Product Development Process for Permanent Downhole Gauge: Key to High Operational Reliability in HPHT Wells
Authors: Balasubramanian Aswin , Flygare James , Shrivastava Pankaj , Smith Callum , Buchan Martin , Quaden Roy 
Published: March 2016

Abstract
A permanent downhole gauge (PDG) in an intelligent completion provides real-time data concerning downhole conditions that can be used to assess the well environment and make informed decisions regarding reservoir and well integrity management. These gauges are permanently installed in severe downhole environments and rarely retrieved to surface for analysis or maintenance. Despite harsh conditions, the gauge is designed to achieve high operational reliability at temperatures of up to 200°C and pressures that reach 30,000 psi. The scope of this paper includes successful application of design for reliability (DfR) principles to streamline the product development process for high-pressure/high-temperature (HP/HT) environments.
Equipment and material reliability is critical to success in HP/HT environments. This paper discusses a reliability focused product development approach and highlights the application of DfR techniques used to qualify a downhole gauge for an operator's prelude floating liquefied natural gas (FLNG) project offshore northwestern Australia. In this major well development project, downhole gauges are used for real-time permanent monitoring at high temperature downhole conditions.
High operational reliability of a downhole gauge is important to ensure functionality throughout facility commissioning, startup, and operations after a well suspension period. Reliable recording of well integrity data during the well suspension period also helps improve operational simplicity.
The DfR process is a systematic, streamlined, and concurrent engineering program designed to meet system reliability targets. This paper examines establishing a reliability specification for a downhole gauge, managing design risk using design failure mode and effect analysis (FMEA) followed by design robustness testing using highly accelerated life tests, leading to a reliability demonstration test program to achieve target system reliability.
This paper highlights an application of optimized DfR strategy along with an efficient reliability qualification test that resulted in successful product development. Improvements to the quality process to ensure reliability consistency between testing and the final commercial deployed gauges are also addressed in this paper.
Additionally, this paper highlights strategic application of a powerful DfR process that aided design de-risking and helped attain system reliability targets, thereby, helping the operator meet its needs. Also demonstrated is how an efficient DfR process led to streamlined product development of a permanently installed downhole gauge resulting in cost and time-to-market improvements while establishing reliability.
Aquatic Oil Spill Remediation by Using Automated Unmanned Boat AUB
Authors: Imtiaz M. , Rajak V. K. , Dei S. , Chhateja J. , Biswas A. 
Published: March 2016

Abstract
The paper briefly discusses the present trend in removal of slick, and puts forward a revolutionary methodology for the same in the form of CSASSB, Cok Sorbent carrying Automated Sub-Surface Boats.
The paper is divided into two parts, the first part discusses the effectiveness of the use of CSASSB's and compare it with the currently used counterparts. The second part discusses the suitability of cork as the appropriate absorbing material. The cork absorbent material is subject to a heat treatment to uncrease its hydrophobicity, its lightness and absorbtion capacity. The working of CSASSB's involves a five step process. The above paper discusses all the above mention steps in detail.
The CSASSB is considerably more fuel effective and eco-friendly than the current ships that are used for the remediation of aquatic oil spills. This system is simple, yet effective. Moreover, the heat treated cork as a sorbent for oil removal in aquatic environment with advantage of being a natural and ecological product. Hence, the CSASSB system with the aid of cork sorbent keeps the ecosystem healthy by removing toxic slick.
The utilization of automated unmanned boats for the skimming of oil has not been introduced. This paper underscores on the feasibility and the advantages of deploying an autonomous vehicle for the same.
Consistent Design Criteria for South China Sea With a Large-Scale Extreme Value Model
Authors: Raghupathi L. , Randell D. , Jonathan P. , Ewans K. C. 
Published: March 2016

Abstract
Existing metocean design criteria for offshore facilities in the South China Sea have been estimated using different data and procedures, some of which are at least partly ad hoc. As a result, it is probable that existing criteria are inconsistent, in the sense that assets designed to the same design codes have different realised levels of integrity. To address this concern in this paper, we apply a large-scale extreme value model adapted to parallel computing environment, applied to the recent high-resolution SEAFINE hindcast database. This not only ensures design criteria that are statistically and spatially consistent but is also faster by avoiding the need for repetitive site-specific analysis.
We have to overcome several challenges before we can apply a large-scale extreme model on the SEAFINE database. These include identifying a spatially consistent set of storm peaks and validating the hindcast data with real measurements. We then estimate marginal return values for significant wave height for locations within a large spatial neighbourhood, accounting for spatial and storm directional variability of peaks over threshold. A quantile regression identifies the extreme value threshold, the rate of exceedance of which is described using a Poisson process. The size of threshold exceedances is described by a generalised Pareto model. The characteristics of the threshold, rate and size models are all non-stationary with respect to directional and spatial covariates, parameterised in terms of (multi-dimensional) penalised B-splines. Parameter estimation is computationally challenging, but a combination of efficient generalised linear array algorithms executed within a parallel computing environment enable maximum likelihood estimation of all models. Bootstrap resampling is used to estimate uncertainties of model parameters and return values.
We thus estimate consistent marginal return values for significant wave height and their uncertainties, at all locations in the spatial neighbourhood. In addition, we quantify directional variability of return values across different return periods. We rigorously validate the proposed spatio-directional model with that of a direction-only model by deriving model diagnostics for the same site and demonstrating equivalent goodness of fits. To our knowledge this is the first of a kind of application of large-scale estimation for the South China Sea. With this approach, design criteria for large spatial domains, non-stationary with respect to the appropriate environmental covariates, can be estimated efficiently, consistently and with quantified uncertainty.
Case Study - Engineered Fiber-Based Loss Circulation Control Pills EFLCC Solves Total Loss Circulation Challenges on Complex Depleted and Fractured Formation in Natuna Sea, Indonesia
Authors: Jaffery Maimoon , Wicaksono Adithya , Pasteris Mathieu , Subhan Muhammad , Amir Baso , Mansur Mohammad 
Published: March 2016

Abstract
The loss of circulation during well drilling and cementing jobs is a serious problem for the oil and gas Industry. Loss of time is very costly and wellbore erosion can lead to inadequate zonal isolation putting the long-term integrity of the well in jeopardy.
Lost circulation was a major challenge experienced by an operator when drilling wells in their 2011 campaign. The site geological prognosis indicated a high degree of depletion in sands and presence of natural fractures. As anticipated, severe lost circulation while drilling was experienced in these formations and drilling efficiently proved to be a challenging process due to heavy mud losses.
An engineered fiber-based loss circulation control pills (EFLCC), based on special engineered fiber system and using a particle size distribution principle were developed to address this issue. The combination of fibers, special solids, and cementitious material was designed and tested in the laboratory to validate its ability to bridge the loss zone while permanently sealing the losses allowing further drilling to the next casing point.
This paper presents the case history and field application of these novel engineered fiber-based loss circulation control pills for the successful treatment of heavy mud losses to formation in wells in offshore gas fields in Indonesia. The paper also includes a discussion of the methodology, material properties and applications.
Well Completion Design Integrity Evaluation Including Thermal and Stress Analysis for Complex Well Completions Offshore
Authors: Chakraborty A. , Asba Madzidah A. B. , Shahreyar N. , Finley D. 
Published: March 2016

Abstract
This paper provides an overview of an engineering design methodology which uses a tubular design analysis validation software program that provides an analytical method for assessing tubing loads, design integrity, and buckling behavior under complex mechanical, fluid-pressure, and thermal-loading conditions. The design methodology is applied to complex wells (e.g., multizone, multistring completions, and intelligent completions). Tubing load evaluation cases for different operating phases are presented for two complex completion types viz. Intelligent Completion and Mutlizone Dual Completion.
Two (2) well study models are presented for discussion and evaluation of thermal and stress-loading analysis: the first model analyses a dual string completion, and the second model analyses an intelligent well completion. Thermal simulation is first performed followed by tubular stress modeling for tubular selection and design. Well models are focused to present tubing-design integrity analysis for multistring and intelligent completions with various anticipated operating loads during the life of the well. Analysis includes scenarios for simultaneous production/injection, commingled zonal flow control with multiposition interval control valves (ICV), and various other well-operating conditions.
Results show temperature/pressure changes for each simulated load scenario in the modeled wells. Also discussed are the impacts of well-operating temperature and pressure change on tubular axial loading, burst and collapse limitations, pipe movement and buckling potential, and resultant forces on completion packers in a multistring (dual completion) caused by tubular stress loading. Furthermore, tubular thermal and stress analysis is discussed for a multizone commingling intelligent well completion having multiposition ICVs with varying flow/injection rates. Results of thermal and stress modeling are evaluated to select and optimize the well completion design as well as identify well operating limits with respect to a set of combined ICV opening positions during commingled well operations.
Dynamic and complex offshore conditions can cause variations in operating temperatures and pressures in multistring and intelligent well completions in which design margins are slim because of production-casing diameter limitations. A detailed stress-loading analysis aided by thermal- and stress-analysis software provides methods for balancing completion design vs. risk. This process provides savings by optimizing well design to meet design integrity standards without being overdesigned.
Optimization of Injection and Production Parameters for Sour Gas Storages: A Case Study
Authors: Chen Z. , Liao X. , Zhao X. , Chen C. , Zhu L. , Zhang F. , Mu L. , Zhou X. 
Published: March 2016

Abstract
To meet with the energy strategy, some natural gas reservoirs in Ordos Basin are planned to use as gas storages. However, most of the gas reservoirs have high content of H2S. If they were operated without parameters optimization, it would put reservoir engineers as well as the environment at rick. Thus, optimization of injection and production parameters of these sour gas storages is urgently needed.
In the paper, using numerical method, the movement mechanism of H2S is studied. With the sensitivity analysis, the effects of some critical factors on H2S mole fraction in produced gas are investigated including ultimate recovery factor, injection rate, production rate, and injection-production rate ratio. Based on the results of the sensitivity analysis, optimal injection-production parameters are selected for a gas storage S24 in Ordos Basin.
The results show that the H2S mole fraction in produced gas decreases as the injection-production cycle number increases. When the cycle number reaches 5, the H2S mole fraction is relatively stable. Additionally, the H2S mole fraction in produced gas hinges heavily on ultimate recovery factor, injection rate, production rate, and the injection-production rate ratio. The decrease amplitude of H2S mole fraction increases as ultimate recovery factor, injection rate, and injection-production rate ratio increase; it decreases as the production rate increases. Numerical results show that after 4 cycles of the operation with the optimal parameters, the produced natural gas from S24 gas storage can reach the quality standard II of commercial natural gas, which is safe for humans and environment.
This study provides us with key technical references for operation of the sour gas storages to ease the contradiction between energy supply and demand.
Realising Un-Swept Potential in Channelised Reservoirs of a Brown Field Using Well Placement Technology
Authors: Mohd Razak S. , Aldha T. , Ismail M. N. , Santoso G. I. , Alang K. A. 
Published: March 2016

Abstract
Rapid production decline of a mature brown field with high density of oil wells has triggered the need to search for trapped and undrained oil to arrest the decline. The field, ABC is located within the Malay Basin offshore Peninsular Malaysia and has been producing since 2002 with 40% reserves already drained. Recent reservoir studies have shown that oil pockets trapped in structural highs in water flooded reservoir and in structural lows in reservoirs with thick gas cap are unable to be drained with existing wells. Horizontal wells, with the aid of well placement technology were drilled to realise the potentials and increase field production.
An integrated approach utilising data from reservoir static and dynamic models and seismic interpretation were used to identify targets in areas of structural highs and lows. Economically viable prospects were selected based on remaining reserves, sand thickness, structure, fluid contacts and locations of nearby water injectors/producers and confirmed by a pilot hole. Based on the results, horizontal well placement is designed with the aid of an imaging tool using resistivity inversion to identify the base or roof of sand to ensure optimum standoff from fluid contacts to prevent early water encroachment or premature gas coning.
Two (2) horizontal wells were drilled with this approach. The first well, X targets 7m of oil column in a structural high bounded by oilwater contact and downdipping top of sand. The pilot hole confirmed presence of oilbearing sand and well placement technology was deployed to geosteer the horizontal section. A 200m horizontal section was drilled 3m above oilwater contact resulting in production of 1500 bbl/day. The second well, Y targets 6m of oil column in a structural low bounded by gasoil contact and updipping base of sand. 70m of oilbearing horizontal section was drilled with 0.5m standoff from the base channel resulting in production of 1000 bbl/day. The usage of well placement technology has aided the subsurface team in landing the horizontal section by navigating the undulations at the base and top of the channel at a scale unresolved by seismic resolution. By analogue, the resistivity inversion confirmed the rugosity of base and top of channel sand in many similar clastic reservoirs. Due to the dynamic of producing reservoir and variability in reservoir quality, the observed fluid contacts are also different for different oil pockets in the same reservoir highlighting the risks that need to be considered when proposing future targets. This strategy coupled with the well placement technology has allowed the realisation of otherwise stranded few MMstb oil in this brown field. This strategy can be replicated for clastic reservoirs in mature brown fields around the globe facing a rapid decline in production.