bluuebunny/crossref_metadata_2025_split huggingface dataset:
Increasing Recovery of Venezuelan Extra-Heavy Oil From a Thin-Bedded Reservoir: First Insights on a New Surfactant-Polymer Approach
Authors: Rodriguez F. , Rousseau D. , Bekri S. , Hocine S. , Degre G. , Djabourov M. , Bejarano C. A. 
Published: March 2016

Abstract
Primary cold production for the extra-heavy oils (4-10°API) of La Faja Petrolifera del Orinoco (FPO), Venezuela, is currently a low percentage (&lt;5%) of the Original Oil in Place (OOIP). Chemical EOR studies are being accomplished in order to increase oil recovery in those thin-bedded reservoirs which host up to 35% of the OOIP, where thermal EOR methods are not convenient in terms of heat losses and environmental issues. Specifically, Surfactant-Polymer (SP) flooding is now considered as a feasible approach to achieve both mobility control and mobilization of residual oil in the FPO's target zones for chemical EOR.
The objectives of this experimental study were to identify the mechanisms in play when surfactant and polymer solutions are injected in cores to displace extra-heavy oil and to assess for the potential of SP flooding for one of the FPO's reservoir. The tests reported were performed with a dead crude oil of 9°API and 4500 cP, an injection water salinity of 6.4 g/L with low hardness and at a temperature of 50°C. The SP formulation consisted of a standard HPAM at rather high concentration to achieve high viscosity and an alkaline-free surfactant formulation providing both low interfacial tension (IFT) and good compatibility with polymer even at high polymer concentration.
A set of surfactant and polymer injection tests has been performed on Bentheimer outcrop cores. These tests allowed demonstrate that injection of the SP formulation after a secondary polymer flood was able to achieve a significant reduction of the residual oil (ΔSo = 80% ROIP). Results of secondary injections of either water, surfactant solution or SP formulation have also shown that mobility control is of tremendous importance to achieve high recovery, even at the core-scale. Oil production data have been confirmed by determination of the CT-scan saturation profiles carried out at each step of the experiments. The results of this study stand as first insights demonstrating at core scale the potential of SP formulation to increase recovery of Venezuelan extra-heavy oils.
Simulation Case Study of Water Shut-off With RPM Gels in an Oil Field in Northern Germany
Authors: Sheshdeh Milad Jokari , Awemo Kilian Nchungong , Yadav Atul 
Published: March 2016

Abstract
Relative Permeability Modifying (RPM) gels are cross-linked polymers which reduce the water and oil relative permeability disproportionately and reduce the water production from a single well. RPM gels are the preferred choice for water shut-off when a well with no zonal isolation is producing from multiple layers among which, no cross-flow exists and at least one layer is producing relatively dry oil. In these conditions application of RPM gels limits the water production until water block or rarely gel desorption ends the favorable effect of the RPM gels.
In this study, a black oil reservoir in north of Germany is screened to examine the feasibility of RPM gels water shut-off treatment. This homogeneous reservoir has been under production for the past 25 years and is heavily water-flooded from early years of production due to its weak drive mechanism. The reservoir is producing with an average of 75 % water-cut and requires urgent water shut-off solutions.
In this paper the screening process with additional focus on the simulation stage of the screening process is described in details. The reason for the additional focus on the simulation part is lack of documented studies on simulation aspect of such projects which has led to non- negligible problems in simulating such treatments.
Once the reservoir is screened considering the petro physical properties of the rocks surrounding the production wells, a water shut-off index is defined for each of the production wells which takes into account the necessity of the well for treatment as well as the risks involved by the quality of the simulation model. Based on the water shut-off index the most promising well is chosen and 3 cycles of RPM gel injection in this well is simulated. Several scenarios are defined to find out the optimum gel volume based on the incremental oil production. The best scenario resulted in 1.54 Million bbl of field incremental oil compared to the "do nothing scenario" in a period of 8 years, performing 3 consecutive gel injections. It is tried to present a detailed work-flow for screening and appraisal of such projects for the similar reservoir and operational conditions.
Comparison of Rheological Properties of Oil-Based and KCl Drilling Fluids
Authors: Werner Benjamin , Lund Bjørnar , Myrseth Velaug , Saasen Arild , Gyland Knud Richard 
Published: March 2016

Abstract
One of the main tasks of drilling fluids is to transport cuttings to the surface to clean the borehole. During this process the fluid is exposed to different flow regimes, shear rates and temperatures. The fluid properties affect the flow behavior, where viscosity, density and gel strength are among the key parameters. Field experience indicates that oil-based drilling fluids perform better in terms of hole cleaning than water-based fluids do, even if viscosity and density values are similar. The exact reasons for this are not entirely understood and increased knowledge will contribute towards more efficient drilling operations.
To deepen the understanding of the hole-cleaning abilities of drilling fluids, a comparative study with oil-based and water-based drilling fluids with similar viscosity profiles was executed. Flow-loop experiments in a 10 m long test section with a free-whirling rotating inner drill string are correlated to rheological investigations on a Fann 35 viscometer and an Anton Paar rheometer. The Fann 35 measurements follow the ISO/API standards and include viscosity and gel-strength measurements. With the Anton Paar rheometer flow curves and temperature dependence were obtained.
This paper presents selected rheological properties in correlation to flow-loop experiments in order to get a better understanding of the unequal behavior in solids transport of the two drilling fluid types. The presented results include yield point and plastic viscosity determination. In addition Herschel-Bulkley and power-law regressions were used to obtain comparable yield-point values. The rheometer measurements provide more detailed data due to extended functionality of the instrument, higher accuracy for each measuring point and a higher number of data points acquired compared to the Fann viscometer.
The yield point of the fluids is expected to influence mainly the static and the low-flow conditions in the wellbore, whereas the plastic viscosity may have more importance in the high-shear region of the flow. To draw back conclusions from the rheology measurements to the flow-loop results, these two points are highlighted in this study.
Liwan Field Development: The First Deepwater Gas Field in China
Authors: Fu Yamei , Gong William , Li Li , Su Rui , Wei Fang 
Published: March 2016

Abstract
LW3-1 gas field is located approximately 310 km southeast of Hong Kong in water depths ranging from 1300 to 1500m. It was first discovered in August 2006. The development of this field aims to achieve optimum recovery factor by concurrent depletion strategy and meet the peak gas nomination of downstream demand. This paper is to present the philosophy and methods used in the overall development plan and the practices during the field production period.
LW3-1 has developed 3 main sands with 9 subsea directional wells including two appraisal wells. Each well has been perforated in single sand to avoid interference among the sands through the wellbore. Balanced depletion strategy has been used to optimize ultimate recovery factor, which was estimated by reservoir simulation, analogue and empirical methods for this field. Before all the wells were put on line, the clean-up operation was carried out to determine the well deliverability after completion. LW3-1 first gas was on March 31, 2014, almost 8 years after its discovery.
The reservoir and production teams have worked closely to generate and implement the initial start-up procedures to meet flow assurance and safety requirements. In order to monitor reservoir and production performance, two down-hole gauges and wet gas flow-meters were installed in each well. A real time production surveillance system and database have been also set up to help efficient reservoir management. The actual reservoir and production data so far has met the expectations in the overall development plan. Good communications within Sand 1 and between Sand 2 and Sand 3 have been observed.
LW3-1 is the first deepwater gas field in China and this paper provides valuable information and experiences of the reservoir management and production monitoring of this field.
De-Risking Drilling Campaign from Geohazards and Overpressured Reservoirs - A Case Study
Authors: Vijapurapu S. , Chong Cindy. K. S. , Lee E. E. , Warrlich Georg M. D. , Mukhopadhyay A. 
Published: March 2016

Abstract
This paper describes the approach of an integrated team of Subsurface and Well Engineers to mitigate the substantial technical risks of a 3-well field development in offshore Sarawak, Malaysia. These challenges ranged from significant geohazard risks in the overburden to uncertainties regarding the extent of potential overpressure in the reservoir section.
The overpressure prediction in the reservoir section arose from detailed analysis of previous exploration and appraisal well abandonments, which indicated the potential for cross-flow from highly pressured sands in the under-burden.
To de-risk the execution phase of this campaign, a multi-disciplinary team of subsurface and well engineers focused on the following key factors: –Evidence for drilling hazards in offset wells–Evidence for cross-flow from deeper high pressured sands into the reservoir section–Geohazards identification in the overburden section–Data acquisition & real time monitoring–Pore pressure prediction–Mud-weight management–Integrated casing design–Hard-stop TD criteria for each well section–A range of "What-if Scenarios" that covered risk identification & mitigation
The well designs eventually selected for this development included both low angle (~40 deg inclination) and extended reach wells (~70 deg inclination) drilled to a target depth of some 21,000 ft.
The successful outcome of this challenging campaign can be attributed to good team integration, rigorous assessment of the risks based on all the available data, and excellent communication and co-operation between the office and rig during operations.
The team created "Well Trouble Plots" for every development well which summarizes the information regarding events such as losses, geohazards and mud weight from the offset wells.
A Successful Attempt to Insert Coiled Tubing Through Parted Production Tubing with a Malfunctioned Downhole Safety Valve to Perform Extralightweight Cement Treatment to Regain Pressure Integrity for Plug and Abandonment
Authors: Yi Jae Seok , Lee Jong Yong , Oh Hyun Jung , Nguyen Tan Khoa , Nguyen Tran Thang , Daohmareeyor Tuanangkoon , Wattanasuwankorn Reawat , Kritsanaphak Kritsana 
Published: March 2016

Abstract
This paper discusses an offshore coiled tubing (CT) application to address a complex well situation and well control issue. Multi-engineering designs and 100% yard testing were used successfully during this campaign.
Parted production tubing was identified some 50 m from the surface. The control line of the downhole safety valve failed and one barrier was lost in the well. This paper describes efforts to regain pressure integrity for a plug and abandonment (P&A) procedure in this live gas well. CT was inserted through the parted production tubing in an attempt to regain pressure integrity.
A carefully planned cement placement strategy was critical to operational success. Key challenges and solutions included the following: Wellhead pressure (WHP), friction, and a highly deviated trajectory affected CT pulling capabilities. Therefore, extra-lightweight cement was used to reduce weight inside the CT.The downhole safety valve failed to close, so the downhole tool was redesigned to help ensure that the tool would not stick.
100% Yard testing for the application was performed to simulate onsite, downhole operations.
Well pressure integrity is a primary priority for global operators. An option to regain pressure integrity was introduced and involved running CT and placing cement into the live well. A combination of multi-engineering designs aided this successful CT campaign. The CT was run through the parted production tubing and the failed downhole safety valve. The well was killed and extra-lightweight cement was successfully placed. The operator was able to regain pressure integrity and perform a P&A procedure. The success of this case study indicated that this procedure could be used for future downhole equipment and tubing failures in live gas wells.
Pushing the Limit of Idle Well Management - A Nationwide Industry Approach
Authors: Mokhtar Shahril , Abu Bakar Samsudin , Wibisono Rahmat , Andika Rizky , Budi Astyo , Narasaiah Suluru 
Published: March 2016

Abstract
In Malaysia, idle wells management has been a constant uphill struggle for most operating companies. Year on year, the end result has shown that number of wells restored are usually lower than the number of wells emerging as idle. In the past, idle wells have also been managed in silo by each operating company which internally for them, it does not portray the actual magnitude of the issue at a nation's level. With 50% of the nation's well inventory are idle and with a locked in potential of 80,000 barrels of oil per day (BOPD), it was essential to implement a major management approach change to mitigate this issue across all the operators.
This paper outlines the master plan rolled out by Malaysia Petroleum Management (MPM); the regulatory body of PETRONAS, across the nation to elevate the focus on the identified challenges that hinders more positive results to be achieved in idle wells management across all Petroleum Arrangement Contractors (PACs) in Malaysia.
Based on a collective analysis, several challenges were identified which have been hindering a more positive result to be obtained from previous initiatives by each operator. These challenges includes work scope prioritization, inefficient resources utilization, poor technical solution, disconnection between wells and surface potential, low economics challenge, weather limitation and lack of collaboration with industry key solution providers.
With the steer and monitoring by MPM, all PACs were able to deliver 60% above target of additional instantaneous production and executed 110% above the restoration planned activities. A parallel effort to reduce the number of emerging idle wells was also executed where the number was reduced by 35%. The overall results have managed to contribute a significant amount additional production for the nation and this new management approach is to be continuously emulated.
Wet Lift as an Alternative Subsea Pipeline Tie-In Method for Marginal Project
Authors: Sahroini Nanang 
Published: March 2016

Abstract
Company developed new APN-E/F gas fields in 2011, namely the APNE-A, APNE-B, and APNF. One of the critical scopes of this project was subsea tie-in work, which was the biggest risk to be managed. This tie-in work was a part of the key success milestones that would affect the overall project completion. There were a lot of constraints and concerns that had to be considered during the execution phase of the engineering, fabrication, and installation work. The wet lift method was chosen after a robust selection process from several options e.g. tie-ins using subsea mechanical connectors, the dry lift and wet lift methods. These options were reviewed against the selection criteria of safety, schedule/shutdown time, cost and quality/integrity for the operation. The wet lift tie-in method for the 24" subsea pipeline was finally selected after being thoroughly assessed by the discipline functions.
The implementation of the wet lift method started with the detailed planning of the resources, material, work sequences and timeline schedules. As a result, the work was safely and reliably executed ahead of schedule.
Innovative Approach of Managing Commercial and Physical Constraints for Complex Gas Network
Authors: Yong H. , Daling R. , Timmerarends B. 
Published: March 2016

Abstract
The Sarawak Integrated Gas Network is one of the largest and arguably most complicated offshore gas networks in the world due to its intricate physical layout comprising of more than 20 fields producing with total capacity of more than 4000 MMscf/d, supplying to 3 LNG plants. As there are various operators in the network operating different Production Sharing Contracts (PSCs) and Gas Sales Agreements (GSA), commercial arrangements are essential to govern the production policy of the network to ensure PSC and GSA obligations and/or entitlements are honoured. Gas quality management by blending of gas is another aspect to be considered as each of the 3 LNG plants have constraints on contaminants such as CO2 and H2S and each field has varying contaminant levels. Integrated Production Systems Model (IPSM) is used extensively for the production forecast of integrated gas networks as pressure interaction via surface network between the different wells have a significant impact on the reservoir performance. However, due to the combination of physical and commercial constraints of the Sarawak Gas Network and the additional complexity due to contaminants management, generic IPSM models are unable to accurately handle both physical and commercial requirements. As such, the traditional workflow for Sarawak Gas Network required a workaround where IPSM models are used in combination with post processing spreadsheet to manually tweak production forecasts in order to honour commercial and gas quality constraints. This was cumbersome and also negated the real benefits of IPSM. The recent rebuild of the Sarawak IPSM model with the Shell proprietary tool, "Hydrocarbon Field Planning Tool" (HFPT), addresses this challenge by incorporating the commercial arrangements within the model. This is made possible as HFPT allows for flexible scripting which enables asset specific functionality to be modeled. The approach is essentially a 2 step approach within HFPT, where field capacity is derived based on physical constraints (as per generic IPSM models) and a second step where production nomination is managed with a series of rules designed to mimic operational practices to align production nomination with commercial arrangements and for gas quality management. The Sarawak HFPT model has been used extensively for Business Planning and resource reporting exercises to ensure the production forecasts are robust and credible. With this novel approach, the revamped Sarawak IPSM model is capable of generating production forecasts which integrates both commercial and physical constraints as well as contaminants management without the need to evaluate the commercial arrangements as a post processing step.
Characterising Coriolis Meters for Use in 3-Phase Flow in Marginal Fields
Authors: Marshall Craig , MacGillivray Alick 
Published: March 2016

Abstract
A significant portion of SE Asia's oil and gas reserves are found in marginal fields containing less than 30 million barrels (bbl) of recoverable oil. The cost of the typical infrastructure to develop these fields can be extremely large which results in some fields being too uneconomical to produce. Instead, some fields are tied-back to already existing infrastructure reducing the requirement for the additional expensive processing equipment. This results in larger production capabilities and more fields becoming economical. However, using this tie-back method requires the produced fluids to be measured and the correct volumes allocated back to the individual wells for both fiscal and ownership applications. As part of the industry standard Measurement Guidelines, the maximum allowable measurement uncertainty for these measurements is often ± 1% (k=2).
For marginal fields the production flowrate is often in the region of 2,000-8,000 bbl/day of oil with expected water cuts starting below 10% and rising to over 50% after several years of production. Owing to limitations in tie-back facilities there are situations where gas break-out in the metering stream can occur (due to insufficient static head). This can result in 3-phase flow through the measurement point which is known to increase the error and uncertainty of measurement. In order to meet the measurement uncertainty requirements a new method has been developed that corrects the mass flow based on live measurement data, PVT models and correction curves generated from a characterisation of the meters.
After a baseline calibration, the meter is then tested in 3-phase flow to give an indication of measurement accuracy and repeatability under these conditions. Correction curves are then generated to correct the meters performance with various quantities of gas and water present. From recent tests, the results from the baseline calibration of the meters showed excellent performance in terms of accuracy and repeatability. During the characterisation tests, large errors were present but these were found to be very repeatable for higher flowrates and corrections could easily be applied. At lower flowrates the Coriolis meters were less repeatable.
This paper will discuss the role of allocation meters in the development of marginal fields and provides a case study on a new method of using single phase flow meters under 3-phase conditions. To the author's knowledge, this method has not been used before and represents a novel use of commercial equipment. The paper will describe the measurement process and discuss the additional sources of uncertainty involved in the process. The paper will end with recommendations for future developments in the region to maximise production and lower costs associated with measurement equipment.