bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving Recovery Efficiency of Polymer Flooding for Middle and Low Permeability Reservoirs in Daqing Oilfield
Authors: Zhang Xiaoqin , Guan Wenting , Pan Feng 
Published: September 2014

Abstract
Daqing Oilfield is a heterogeneous sandstone reservoir with multiple layers. Polymer flooding in the primary oil layers has achieved significant technological and economic effects. And polymer flooding in the secondary oil layers of middle and low permeability (100~500mD) has began since 2003. Compared with the primary oil layers, the secondary are of thinner sand bodies, lower permeability, narrower channel sands and worse connection. For that reason, following measures are taken to improve the polymer flooding efficiency in these layers.
Layers are divided and those of similar properties are grouped to form development series. By doing so, layer differences are reduced and the recovery efficiency is enhanced.
Injector-producer spacing is shortened and the relationship between injection and production is optimized to improve the controlling degrees of polymer flooding
The right time and proper layers for measures of fracturing in producers and in-depth profile control in injectors are optimized to improve the effects of these measures.
By doing so, recovery efficiency of industrialized polymer flooding in the secondary oil layers is enhanced by 10%.
Advanced Production Operations Support Applying Dynamic Simulation Techniques – Blacktip Gas Field in Bonaparte Basin, Australia
Authors: Yokote Ryosuke , Yamada Tatsuya , Derrij Joseph , Maniscalco Giuseppe , Mantecon Juan Carlos 
Published: September 2014

Abstract
This paper describes the work flow adopted by Eni Australia to support Blacktip daily production operations. The Blacktip gas field is located offshore in the southern Bonaparte Basin, Australia. Eni Australia is the operator for the Blacktip gas field and holds 100 per cent (%) working interest. Production from the Blacktip gas field started in September 2009 and has been the primary source of gas for Darwin, Northern Territory. The Blacktip gas project consists of a normally unmanned Wellhead Platform (WHP) at a water depth of 50 meters (m), a 110 kilometer (km) offshore Gas Export Pipeline (GEP) and the onshore Yelcherr Gas Plant (YGP). Two deviated production wells were drilled and completed on the WHP in September 2009. Well intervention was carried out on the WHP to shut off a lower production zone and perforate the main production zone in June 2013. Untreated gas from the wells is directly sent to the YGP via the GEP, without offshore processing. The gas is treated at the YGP to meet the customer's specifications and it is sent to Darwin via an onshore gas transmission pipeline operated by a third party. Condensate is processed and stored at the YGP, and offloaded via a 10 km offshore offloading line.
Multiphase flow numerical transient simulation (dynamic simulation) techniques have been used to establish the work flow to support daily production operations. Three fit for purpose models have been constructed in order to fulfill this task in a timely manner. They are the well(s) model, the GEP model and the offloading line model. History matching of the GEP model has been routinely conducted to monitor pipeline performance and to provide the operations team with relevant information such as liquid volume in the GEP, slug prediction, etc. The condensate offloading line model was used to develop operational guidelines for the first offloading operations conducted in July 2010. In due course, dynamic simulations were applied to support well operations using well models. Regular history matching has been conducted to validate the models and monitor well performance. The well model was also used to establish a sound and safe operations plan for the well intervention campaign, to change the production zone. The application of dynamic simulation is now an integral part of daily production operations for the Blacktip gas field.
Drilling on Target: Saving Rig Time While Maximising Reservoir Exposure in a Horizontal Well
Authors: Hassan Siti Norhajar , Kassim M Shahril , Ariffin Ahmad Jazim , Oruganti Bhargava Ram , Santoso Gagok , Permanasari Dian , Alang Khairul Anuar , Yusuf Nora 
Published: September 2014

Abstract
A pilot hole is a commonly used method to reduce uncertainties while drilling a horizontal well, but it is a costly procedure. Thus, there is high demand in the industry to have alternative solutions to reduce total well cost but still achieve the well objectives. This paper presents a case study of a horizontal well in the Malay basin that was landed accurately in the target oil reservoir without any pilot hole and drilled optimally in the target layer with improved reservoir thickness evaluation.
The well target was a sand layer with average thickness of 3 to 5 m and variation in quality. Unlike the other target reservoirs in the field, there was no concern over fluid contacts within this sand; thus, options to eliminate a pilot hole were considered feasible. The main challenges were the structure determination, formation dips, and thin-sand thickness that would cause significant impact to landing accurately and achieving a minimum of 300-m lateral length inside the reservoir.
A full suite of logging-while-drilling (LWD) measurements, combined with a model-compare-update well-placement method, were used during landing to address these challenges. For the lateral section, an additional deep-directional resistivity measurement was used for boundary detection, which enabled proactive geosteering to avoid premature exit. As a result, the horizontal well was landed accurately in the target reservoir layer without the need for a pilot hole; thus, significantly reducing the well cost. Furthermore, a 500-m lateral section was maintained 100% inside the target reservoir, which exceeded the initial objective. A post-drilling analysis was performed using density image dip-picking and bed-boundary mapping results. The drilling polarity along the lateral section could then be determined and the true stratigraphic thickness of the target reservoir extracted, which resulted in a more accurate reservoir thickness evaluation. The methods and processes used in this case study yielded best practices and recommendations for drilling and evaluating similar reservoir conditions elsewhere.
Case Study: Factory Drilling Australia's Unconventional Coal Seam Gas
Authors: Smith Glenn , Waguih Ahmed , Redrup John , Kholgh Arman Nick , Aguirre Eduardo 
Published: September 2014

Abstract
The Queensland Curtis Liquefied Natural Gas (QCLNG) project is the world's first project to convert coal seam gas (CSG) into liquefied natural gas1. The project involves drilling thousands of wells in the Surat basin, installing an underground 540 km long pipeline to Gladstone and the building of a plant on Curtis Island to liquefy the natural gas. The project, which has been under construction since 2010, is on schedule to provide LNG for export from the end of 2014.
The multi-billion-dollar investment by QGC, the Australian business of BG Group, is one of Australia's largest current capital infrastructure projects. Schlumberger has been contracted to deliver on the drilling and completion phase of this critical project.
The "Factory Drilling*" project operates nine rigs using a multidisciplinary team consisting of project management staff utilising/coordinating logistics, warehousing, wellsite management, cementing, wireline, bits, solids control and directional services/personnel. The project has overcome significant challenges in the business development and start-up phases. Through the application of the "excellence in execution" philosophy, records have been broken and new performance benchmarks set in this unconventional CSG market.
Since the start of the project in early 2012, using the team's project management abilities and incorporating LEAN (the identification and steady elimination of waste from operations) initiatives, the project has drilled and completed more than 1000 wells, some in as little as 2.15 days (drilling time) and 1.04 days (completion time).
The optimisation initiatives have contributed towards reaching a state where the project is currently performing very close to the technical limit, yet challenges are still ahead to maintain and mature the safety culture and improve the operational efficiency even further.
Well Integrity - Moving from Firefighting to Strategic Planning
Authors: Ceray A. , Borzel K. , Spowage A. C. 
Published: September 2014

Abstract
A mature Well Integrity Management System (WIMS) is essential to assure the sustained integrity of a well. When adequate systems and processes are not in place the result is a reactive or firefighting approach to integrity management. An immature WIMS will typically result in a higher risk of a major incident occurring, an increased frequency and severity of minor integrity issues as well as reduced long term production.
Based on real world experience gained through the management of over 10,000 wells and the extensive experience of one of the largest well asset integrity management teams in the industry, the key common transformative elements required to move from a reactive to a strategic WIMS has been developed. A well integrity-focused maturity model is outlined and real world experience used to illustrate typical characteristics of organisations operating at each integrity management maturity level.
In order for companies to enhance their level of maturity a stepped roadmap approach is proposed. As the specific details of the path to a mature WIMS will be unique, this work identifies the common transformative elements and places them as milestones on the roadmap. A full roadmap will need to be populated with well specific details for each of these milestones. This will facilitate a company's progressive improvement to attain each level of WIMS maturing.
Prediction of Productivity Decline in Oil and Gas Wells Due to Fines Migration: Laboratory and Mathematical Modelling
Authors: Siqueira F. D. , Yang Y. , Vaz A. , You Z. , Bedrikovetsky P. 
Published: September 2014

Abstract
Suspension-colloidal transport in porous media with the particle detachment usually exhibits a significant permeability decline. It occurs due to mobilisation and migration of detached colloidal or suspended fines with their straining in thin pores of the rock. Numerous laboratory coreflood tests show that the time for permeability stabilisation counts for hundreds of injected pore volumes, while the classical filtration theory assumes the released fines transport by the bulk of the carrier fluid yielding one pore volume injection to stabilise the permeability. In the current paper, the stabilisation delay effect is explained by slow drift of the mobilised fines near to pore walls. The basic flow equations for a single-phase particle transport in porous media with velocity lower than the carrier fluid velocity are proposed, and the analytical model for one dimensional flow with particle release and straining under the piece wise increasing velocity is derived. The laboratory data are in a good agreement with the results of mathematical modelling. The analytical model for well inflow performance is developed. It successfully matches several field cases.
A New IOR Method for Mature Waterflooding Reservoirs: “Sweep Control Technology”
Authors: Wu Xingcai , Xiong Chunming , Han Dakuang , Liu He , Gao Shuling , Xu Hanbing , Dong Fan , Ren Fangxiang 
Published: September 2014

Abstract
For improving the recovery of water flooding heterogeneous oil fields, the classical conformance control method is to enlarge the swept volume as far as possible, usually by fine layering, profile control and water shutoff, and fracturing and acidizing, etc. However, with watercut rising, the remaining oil distributes in deep reservoirs, making the classical methods less effective. “Sweep Control Technology (SCT)”, a new IOR method, is put forward. The whole production-injection flowing field is taken as the studying target. The waterflooding effect impacting factors were classified into three levels: large-scale macroscopic heterogeneity, middle-scale mesoscopic heterogeneity and pore-scale microscopic heterogeneity. Based on the impact of the three levels of heterogeneity on sweep efficiency, we developed new corresponding SCT materials. For large-scale heterogeneity, we put the materials in accurate place to effectively inhibit water flow prevailing channels. For the middle and small scale heterogeneity, the water flow is diverted to achieve effective sweep control by means of effective material migration. So that we can realize complete adjustment and control of the whole flowing field to achieve efficient remaining oil displacement, and to improve the recovery of water flooding phase. The research and experiments in laboratory and field have proved the advancement of the method.
Identification and Modeling of Inter-Reservoir Cross-flow Using a Novel Material Balance Method
Authors: Montague E. T. , Airul Hafneh 
Published: September 2014

Abstract
A detailed material balance study of the Northern Area Deep reservoirs was conducted to address anomalous trends identified from p/Z analyses. The material balance study was conducted using a novel application of Petroleum Experts' MBal software, and determined that previously unrecognised volumes of gas were cross-flowing between reservoirs predominantly behind casing in the wells. The magnitude of the cross-flow volumes significantly impacted well and reservoir performance, but were unable to be modelled or quantified.
The approach that was adopted to model the inter-reservoir cross-flow using MBal as a “sub-surface abacus”, whereby injection of gas into the reservoirs was introduced manually to represent influx due to cross-flow. Additional production (on top of allocated produced volumes) was introduced to model the corresponding efflux of gas. Manually maintaining a volumetric balance between the efflux and influx profiles was difficult, but achievable, and provided an internally consistent method to model the complex dynamics of this reservoir system.
Detailed simulation studies have been recently conducted on the Northern Area Deep reservoirs and have complemented the findings from this material balance study. The MBal model has been updated regularly with over 6 years of additional production and pressure data, and the model is still holding a good history match. This has provided high confidence in the model's robustness, and validates the adopted methodology, which has broader applications to enable material balance modelling of “non-geological” inter-reservoir cross-flow.
The purpose of this article is to present the methods and practices employed in this process and to show how they can be applied to other fields/reservoirs.
Brownfield-Surface Network Debottlenecking and Mitigation Analysis: A Case Study
Authors: Haryanto E. , Thomson J. , Bolanos N. , Soendoro F. H. 
Published: September 2014

Abstract
When liquid production has levelled out despite continuing drilling and adding new wells into a production network, a surface network bottleneck issue may be suspected. The initial stage and cost-effective option in determining whether surface production was being restricted by excessive backpressure on the wellhead, or a certain part of the facility, can be done using surface network modeling. The result of surface network modelling itself is very often challenging due to minimal data availability and data uncertainties, or unclear characterization between a surface bottleneck issue and other problems such as artificial lifting and poor well performance. These challenges may be related to each other and often impede conclusions in determining any source of bottlenecks.
We discuss a case study and elaborate a detailed workflow to utilize a fully benchmarked surface network model with individual well models for bottleneck identification. Using the proposed workflow, production data analysis is performed prior to building the surface network model itself and eliminates confusion between production optimization related issues and any surface bottleneck. Benchmarking of the model and selection of appropriate flow correlations are used to provide a robust surface network model. Some pipelines or connections with potential bottleneck problems are successfully identified from the modelling that are later compared with field inspection to seek any potential bottlenecking evidence or indication. Based on high-level diagnosis, amongst many other possibilities, an emulsion-management challenge was suspected in the root-cause analysis, especially for gas-lifted wells. The study was completed with sensitivity analyses of different debottlenecking scenarios to further evaluate potential mitigation plan to maximize the brownfield's life and achieve the field's economics objective.
Successfully Improve Oil Recovery Using In-Situ Gas Lift and Gas Dump Flood at North Arthit Field, Gulf of Thailand
Authors: Rinadi M. , Dechanuwong V. , Harnboonzong P. , Lerlertpakdee P. , Rodpranee W. , Sriyanong P. 
Published: September 2014

Abstract
North Arthit field in Gulf of Thailand is a gas condensate field, but also has oil reservoirs that produce from number of wells. This paper explains the implementation of in-situ gas lift and gas dump flood technologies to increase production and improve recovery from a partially depleted oil reservoir in North Arthit field. A simulation study was performed to understand reservoir characteristic, drive mechanism and expected oil rate prior to the field implementation; the study results were to allow cross flow within the tubing to dump high-pressure gas from a deeper gas reservoir into the oil reservoir to increase reservoir pressure and sweep the oil to a nearby producer. This successful pilot work has opened up the opportunities for other small oil pools in Gulf of Thailand. A proper design of the in-situ gas lift and dump flood will significantly improve the oil recovery.
Linking Subsea Networks To LNG Plants: The Challenge Of Diurnal Swing
Authors: Sbriglia G. , Hester K. , Bonfanti R. , Castellitto T. , Negri E. , Montini M. 
Published: September 2014

Abstract
Numerical simulations have been performed on a gas field located 50 km off the coast in ultra deep waters. The production scenario combines field-to-shore multiphase production with onshore LNG processing facilities, which are based on gas turbines driving directly refrigeration compressors. One of the challenges to be faced in the design is the so called diurnal swing, which is the daily variation in requested LNG feed gas based on ambient conditions changes and hence LNG operating efficiency. Indeed, gas turbines available power is directly related to ambient conditions, like air temperature, pressure, etc; at the same time, it is recognized that the major effect is due to the air temperature. This work assesses the need to explicitly model the diurnal-swing effect and how it can affect the ability of the subsea system to meet gas deliverability requirements without adjusting the subsea wells choke on a half-day basis.
The system was modeled as steady-state, with average forecasted production rates, and also explicitly accounting for the daily flowrate variations. Transient simulations showed that the pressure built up and blew down very quickly in response to rate changes. These cyclical pressure variations must be managed by the subsea system and indeed affected well productivity. The higher backpressure did not allow some wellhead pressures to be drawn down sufficiently to meet requested gas rates, especially in late years when the field is more depleted. However, this shortfall was not realized in the steady-state modeling where the rate and pressure remains at a constant value. On the other hand, liquid content actually improved under transient diurnal-swing conditions compared to assuming an average daily rate. This was due to the periods of higher flowrate and higher pressure.
Overall, this study highlights for the first time that an explicit assessment of the diurnal-swing should be performed for such subsea systems along with the normal steady-state approach during all phases of the development.
Increasing Production Through an Innovative Analytical Approach in a Brown Field - A Case Study
Authors: Mandal Dipak , Bt. Ahmad W Zuraidah , Chaw Kit Teng , Bt. Hassan Siti Norhajar , Mansur Roslan 
Published: September 2014

Abstract
Early monetization of resources has become the key to have a competitive edge in our oil business today. In brownfields, this requires critical analysis of the existing performance, the sweep pattern, well drainage, and faster generation of robust cost effective redevelopment plan followed by rapid execution to get those early barrels. In Peninsular Malaysia BX is an oil rim reservoir with a large gas cap and moderate water drive. Oil production has declined rapidly in last few years with increasing GOR and water-cut. Existing models could not explain the current production behaviour. Apprehending building new models would take significant time, thus to arrest the unexpected decline in oil production, a classical reservoir engineering approach was adopted to identify bypassed oil and propose infill wells for additional production. With integration of production data, seismic, well logs and sand geometry, an innovative approach was used to find the less depleted areas. Well decline analysis, complemented by polygon balancing and normalised EUR bubbles at wells helped to identify locations where infill wells were proposed.
The team deliberated the subsurface and operation risks and assessed them as internal or external risks, prioritised them and built a mitigation plan. These fast track infill wells without dynamic model were very successful in increasing production and reserves, and provided high economic returns due to reduced costs and early oil. The field oil production increased by more than 80%.
This paper covers how the analytical approach with polygon balancing and normalised EUR bubbles was carried out to find the undrained areas. It also highlights challenges encountered during the planning and execution phases and the steps taken by the integrated team to overcome them. Encouraged by this success a number of this early monetisation projects were initiated which gave positive results thus proving the success of the technique.