bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pushing the Boundaries of Reservoir Characterisation of Ultra Deepwater Turbidites Reservoirs via Formation Testing and Advanced Fluid Sampling; South East Asia
Authors: Zakei A. , Mahadi K. A. , Ngan A. , Kassim M. S. , Haddad S. , Heng L. K. 
Published: October 2017

Abstract
Formation evaluation quality and cost efficiency are crucial in ultra-deepwater reservoir evaluation. Reservoir properties such as fluid composition, formation pressure, and sand producibility are critical in the exploration and appraisal phases of the well life and represent a key input to comprehensive production and reservoir engineering studies in the development phase. In addition, contaminants measurement including hydrogen sulfide (H2S), carbon dioxide (CO2), and mercury are important to address challenges in the planning and utilization of equipment and production facilities.
This work is based on recent experience in South-East Asia that demonstrate prudent operatorship in maximizing value of information (VOI) from exploration drilling and evaluation. These formation testing is conducted to address the inherent uncertainty in reservoir characterization; particularly reservoir connectivity, producibility and presence of fluid's contaminants. Integrated measurements such as core data, log analysis, image logs, pressure data and fluid sampling were utilized to better characterized the reservoirs. Advanced sampling method was conducted to evaluate presence of contaminants including H2S, CO2, and mercury in the reservoir. Onsite lab services were utilized to handle and analyze the captured sample on location for better contaminants evaluation. In addition, formation mini-DST testing was also conducted to further understand interval rock and pressure properties at larger scale.
The application of this proposed approach is critical to reduce the subsurface uncertainty especially on reservoir and fluid properties; which inputs are used to prudently design future field development facilities. Field data and workflow demonstrating formation evaluation techniques will be presented in this paper. Lesson learned and best practice will also be explained supported by lab analyses and results.
Optimising Operation Oversight of Oil and Gas through Aerial Surveillance
Authors: Prasetya Afriandi Eka , Sufiadi Eri , Sadik Hermawan Umar 
Published: October 2017

Abstract
Aerial surveillance for oil and gas operations can help in decision making process for a quick and appropriate response to deal with matters that potentially detrimental to the country.
SKK Migas, in supervising and controlling the upstream oil and gas activities in Indonesia have made a good security system and mutually coordinated between operators and other institutions, but there are still several of that difficult to be covered and need to be improved by using technology effectively. Based on the issue reviewed it was recommended to utilize technology-based security systems to improve the security of the operator's working area and develop a security system with the support of drone technology in collecting pictures and videos oil and gas activities. Photos and videos obtained through the drone and then compiled to give an overview of monitoring activities, analysis, and geographic location conditions in the working area.
Aerial surveillance activities by drones in the pipeline operation and maintenance area show the growth of residential areas along the pipeline right of way and the increase of population and industrial activities in the vicinity so that will affect to the increase of the potential risk of pipe explosion. By using drone technology to monitor the pipeline operation and maintenance area, it can help for a quick and appropriate response to prevent a greater risk and implement procedures to minimize impact on the environment.
This paper outlines the utilization of drones to monitor the gas pipeline network in one of the oil and gas operation and concluded by recommending the use of drones to provide a snapshot of operational safety and prevent risks to the community.
Enhance ESP Performance in Sandy and Gassy Applications
Authors: Quintero Regulo , Elmahbes Reda , Malino Antoni , Larez Arsenys 
Published: October 2017

Abstract
The dynamic conditions for wells present multiple challenges for conventional electrical submersible pumping systems (ESPs). Sand production, formation damage, and free gas are some of the problems that require reliable solutions to enhance the performance and run life of the ESP system and increase production.
Continued monitoring of performance and operation of multiple ESP systems installed in the Boscan field has enabled the creation of best practices and technologies to improve ESP performance and maximize production. Integrated ESP solutions with sand control helped reduce the amount of sand entering the ESP system, significantly increasing its performance and reliability. In addition, a sand control filter provided efficient gas separation without moving parts, enhancing the ESP system performance and improving well productivity. Based on the application, sand size, and the amount of free gas, different sizes of sand control filters can be proposed to enhance the ESP performance in gassy and sandy applications.
This paper describes the benefit of ESP integration with sand control filters in high sand and gassy oil wells. This solution showed significant improvement in overall system reliability and performance. In addition, it helped the operator to economically produce from the wells and maximize their recoverable reserves. This solution also reduced operational expenditures (OPEX) and downtime related to ESP failures due to sand and pump gas lock caused by high free gas in the pump. The operator also reduced surface equipment maintenance costs as a result of the decreased amount of produced sand.
Wireline Logging under Pressurized Mud Cap Drilling Condition - A Challenging Operation
Authors: Mohammad Suria Melanie , Nathan Kumar , Kyi Ko Ko 
Published: October 2017

Abstract
Drilling wells in pinnacle carbonate formations, which are gas bearing and have karstified zones, is a complex operation due to severe mud losses encountered in these formations. Currently, the safest way to drill such formations is to deploy Pressurized Mud Cap Drilling technique whereby a sacrificial drilling fluid, usually sea water, is used to control the formation fluids from flowing into the well. At the same time, a light annular mud (LAM) is injected into the annulus to prevent any gas from migrating upward in the annulus. Drill cuttings are injected into the loss zone higher up in the well and as a result there are no returns to the surface. In wells drilled using this technique, wireline logging is usually discouraged due to safety reasons. Logging While Drilling is the only method of acquiring well log data. Due to the dynamics involved in PMCD mode of drilling, these wells tend to washout quite often, resulting in LWD logs which are of dubious quality. This is due to the fact that LWD log data is acquired while the drill string is being rotated and cannot be pushed against the formation like wireline logging tools such as the density and neutron porosity tools. This usually results in log data which are heavily affected by the drilling fluid, rendering them questionable for formation evaluation. Therefore, wireline logging has been considered as an option to acquire data which is more reliable than the LWD logs as the wireline logging tools can be pushed against the wellbore wall, providing better contact with the formation. Additionally, there are other logging tools such as formation fluid sampling, formation resistivity imaging and rotary sidewall coring tools which are usually run on wireline to provide complete evaluation of the formation. The main deterrence against wireline logging in PMCD wells is safety. In order to acquire data using wireline logging safely, LAM must be continuously pumped into the well annulus to prevent fluid migration. This means some form of injection method must implemented while wireline logging tools are deployed in the well. Furthermore, as the drill string is no longer present during the wireline logging operations and the well is underbalanced, wellhead pressure control equipment must be deployed to prevent the well from blowing out. This paper discusses the planning, execution of wireline logging operations under PMCD condition and the results obtained in a well drilled in pinnacle carbonate gas field.
Lessons Learnt during Hydrofracturing Campaign in Tight Retrograde Gas Condensate Reservoir – A Case Study
Authors: Anand Saurabh , Tiwari Shobhit , Tibbles Raymond Joseph , Pathak Shashank , Siddharth Punj , Goyal Rajat , Vijayvargiya Utkarsh 
Published: October 2017

Abstract
Raageshwari gas field is located in RJ-ON 90/1 Block in western India with Cairn, Oil & Gas vertical of Vedanta limited as the majority partner and Operator of the field. The field is located in a remote environmentally sensitive region which complicates the gas development project. The reservoir comprises streaks of volcanic sands with low permeability (~0.1 mD). Hydraulic fracturing is required to achieve commercial production from the field. Wells are generally drilled to a measured depth of 3500m and are completed with a 3.5" monobore. There have been 5 fracturing campaigns to date in the field. The previous campaigns were plagued by inefficiencies due to operational, technical, and logistical issues which resulted in cost over-runs. This paper describes the key learnings that were attained and implemented during the last campaign in which ~ 100 fracturing treatments were successfully pumped.
Learnings and observations from the campaign can be placed into four categories: HSE: Observations made through the campaign which reduced a) the risk in operations, b) waste generation and c) gas flaring (almost no flaring was required in the last campaign).Operational learnings: Including on-site lessons learnt during the fracturing treatments, post-frac coil tubing cleanout, and post-frac surface well testing. Implementation of these learnings enabled significant completion efficiency gains by the end of the campaign.Technical learnings: Key elements of the frac design and treatment which resulted in more effective treatments. The percentage of reservoir connected with fractures increased more than 30% which had significant impact on well productivity and estimated ultimate recovery (EUR).Contractual learnings: Key points that improved contract management and resulted in efficient and smooth running operations.
As a result of implementation of the lessons learnt, days per frac and cost per frac were cut in half. The fracturing campaign was completed ahead of schedule without any LTI incident.
Implementation of these learnings resulted in exceptional improvements in the HSE performance, operational efficiency, and well performance which has significantly improved the economics of this tight gas development project. These learnings are applicable to any non-conventional tight gas development project and are especially important given the current market conditions which require a focus on efficiency and adaptation.
Open-Hole Multistage Completion System using Improved Water-Swellable Packers in Tight Sandstone Gas Reservoir – A Case History from East Sulige Field, China
Authors: Tong Zheng , Wang Yongming , Wei Ran , Xue Jianjun , Li Ming , Qian Jie , Shen Zejun , Zhang Yanming 
Published: October 2017

Abstract
Water-swellable packer (WSP) is used rather than oil-swellable packer (OSP) for open-hole packer-sleeve (OHPS) fracturing and completion in China. In this paper, the two improved WSPs including hybrid external casing packer (ECP) and WSP with corrugated packing element are developed to solve the problem of tripping and deployment in irregular horizontal wellbore. The hybrid ECP combines mechanical-set packer with water-swellable packing element. The WSP with corrugated packing elements makes structure more compact than the traditional packer.
The two solutions were successfully evaluated by bench test. The former combines the feature of high-rating sealing performance, instant fracturing operation with swelling-assistant isolation. The latter has advantages of smaller size, high reliability and easy tripping over traditional WSP.
During OHPS multistage fracturing trial in Sulige gas field, the first five-stage operations are performed with hybrid ECPs and the last two-stage fracture diversion treatment are performed with new WSPs. The fracture diversion was carried out by injecting temporary plugging agents (TPA). The sealing effectiveness is fully validated by long-time ambient pressure differential during fracture diversion. It is shown from field operation that the new OHPS based on improved ECPs is able to meet the requirements of completion and stimulation in irregular horizontal wellbore for tight sandstone reservoirs.
A New Approach of Pressure Profile and Oil Recovery during Dual and Single Carbonate Core Flooding by Seawater and CO2 Injection Process at Reservoir Conditions
Authors: Zhou Xianmin , AlOtaibi Fawaz , Kokal Sunil , Alhashboul Almohannad , Al-Qahtani Jassi 
Published: October 2017

Abstract
Sweep efficiency during waterflooding and CO2 miscible injection can be challenging because of channeling and bypassing of injecting fluids. Some of these factors include reservoir heterogeneity, permeability contrast and gravity override. These factors contribute to reduced volumetric sweep efficiency in both sandstone and carbonate reservoirs. To study the effect of reservoir heterogeneity on pressure profile and oil recovery, and accurately describe the displacement mechanisms during seawater and CO2 flooding, an effective experimental methodology including the laboratory set-up and procedures are proposed in this paper. Dual core flooding experiments were conducted at reservoir conditions using live oil, seawater, supercritical CO2 (sc-CO2), and two composite plugs with different permeabilities. Two composite core plugs, a high permeable core plug (HPCP) and a low permeable core plug (LPCP), were placed in parallel in a coreflood apparatus. No crossflow of fluids occurred between the high and low permeable plugs. Different injection schemes were completed, which included seawater flooding, initial sc- CO2 injection, gel slug injection for conformance control and a second sc-CO2 injection. In addition, two experiments with seawater and continuous CO2 injection were completed with the same conditions in a single coreflood for comparison with the dual core flooding experiments.
The results indicate that the dual core flooding technique is an effective method to evaluate the performance of IOR and EOR processes, especially involving CO2 or gas injection. The profiles of differential pressure across both HPCP and LPCP show a demonstrable distinction. The differential pressure across LPCP is higher than that of HPCP for both seawater and supercritical CO2 (sc-CO2) injection before breakthrough, and drops to levels similar to that in HPCP after breakthrough. A substantial increase of differential pressure in HPCP (up to 200 psi) was observed during base gel slug injection, which indicates that in- situ CO2-emulsion was generated and was able to block the high permeable zone and resulted in displacing fluids into LPCP, therebyimproving sweep efficiency in the LPCP. The comparisons of oil recovery by seawater and sc-CO2 injection and the pressure profile between both dual core flooding and the single core continuous sc-CO2 process (horizontal and vertical injection) are discussed in this paper.
Proactive Reservoir Surveillance That Leads to Prudent Reservoir and Asset Management: A Pleasant Surprise in Understanding AB Field
Authors: Zakariah A. , Mahmoud H. A. , Rosland E. A. , Mandal D. 
Published: October 2017

Abstract
AB field has undergone secondary recovery of water injection for pressure support and sweep efficiency improvement. From proactive surveillance program, it was further discovered that AB field performance is improving without water injection. Pilot shut-in water injection study initially commenced post 5 years of production. From the pilot water injection shut-in, surveillance data was used for thorough analysis to conclude that secondary recovery through water injection will reduce field recovery due to early water out coupled with moderate to strong aquifer strength.
Close pressure monitoring, surveillance database, and other diagnostic plots used to gauge the water injection healthiness in AB field. Reservoir modelling was built to validate the implication of water injection secondary recovery to the field. Complete surveillance data and gathering method will be presented in this paper to permit readers to replicate the analysis prior to conclude secondary recovery type of mechanism, typically water injection, is beneficial to the field or proven otherwise.
Pilot shut-in water injection has proven the following: (1) It was observed that AB field pressure still maintains above the pressure target of initial Field Development Study, (2) Watercut performance has significantly increased post pilot water injection shut-in, (3) no substantial impact on the reserves loss, while in contrast, water injection stoping will improve recovery due to delaying the wells watered out time. For this marginal field of AB, an incremental of 0.8-1.7 MMstb reserves recovery will contribute to higher recovery factor. This is also due to the moderate to strong aquifer strength against weak to moderate aquifer strength anticipated earlier in FDP.
Casehole contact logging was conducted at two wells in the field to monitor the contact movement. From all the observation and analysis conducted, AB field was further optimize by the Reservoir Management Plan (RMP) revision. Lesson learned from the case study will enhance others' understanding and view prior to deciding on secondary recovery method to any field. RMP study should be updated as the production continues and once more data is acquired from the right surveillance program.
Poro-Fluid Facies Identification with LWD Nuclear Magnetic Resonance NMR Factor Analysis in Karstified Carbonate Reservoir - Case Study from East Java Basin
Authors: Budi Abrar , Rachman Tubagus Reggie , Othman Tengku Rasidi , Ihsan Pasaribu 
Published: October 2017

Abstract
The well within the context of this paper is carbonate formation in East Java basin deposited in late Oligocene to early Miocene. It is divided to 3 reservoir targets and potentially has different flow units, which believe predominantly due to secondary porosity. The well testing in exploration well drilled on the carbonate reservoir has commingled mixed between oil and water. Further appraisal well was necessary to be drilled to evaluate hydrocarbon saturation. The studied well was designed by combining the development and appraisal objective, therefore the deviation of the well was significantly high angle well.
The conventional water saturation from resistivity based Archie did not give conclusive result because of fresh water environment and low contrast resistivity features. Utilizing nuclear magnetic resonance (NMR) log has been used for decades on carbonate evaluation through T2 (transversal relaxation time), and T1 (longitudinal relaxation time) for determination of pore type/system and differentiation of irreducible water from free fluid volume with applying fix pre-determined T2 cut-off.
NMR log acquired while drilling gives the continuous T2 distribution which can be utilized to derive the poro-fluid facies on the porosity system from the measured actual T2distribution. The new technique based on statistical "factor analysis" search the peak response from each T2 distribution in depth level. Each changing on the T2 peak distribution on every depth will be recognized as actual cut off the T2 distribution and it will represent the poro-fluid facies constituents inside the T2 distribution. This paper will discuss the application the technique applied to the LWD NMR for determining poro-fluid facies analysis on the carbonate reservoir. The ultimate purpose is to identify the free fluid type presence on the porous rock. It will also discuss the advantages of this technique applied to the NMR acquired while drilling and use synthetic based mud to minimize the invasion and the ambiguity of filtrate invasion that may effect the free fluid determination on the rock.
Reactivation and Production Optimisation of Teluk Berau A TBA Field, Salawati Basin, West Papua
Authors: Suwandhika Bayu , Mubaraq Munajat , Suhendro Suhendro 
Published: October 2017

Abstract
The additions of oil and gas reserves through enhance oil recovery (EOR) projects and or finding new exploration plays are challenging nowadays. Reserve replacement ratio is far from ideal condition especially for mature PSC in Indonesia. Low oil price environment worse this condition by decreasing revenue for operator. Both exploration and EOR will require three to five years to add reserves and improve the oil and gas production rate. In another hand, marginal fields which still have remaining reserves and the potential for production are less considered for development. Integrated and careful scenario should be arranged to deal with.
TBA Field is an offshore field located in Salawati Kepala Burung Block, West Papua Province, Indonesia. It was discovered in 1975 and had been producing since 2006. From the initial data, this field was expected to produce up to 4.32 MMBO from 9 MMBO OOIP. Current recovery factor is around 45%. There are 3 wells on this field, with two actives and one already been P&A. TBA Field was closed in 2010 with the last oil production 1,250 BOPD from 1 well. The remaining reserves and production profile TBA became unattractive for contractor's due to high cost for the rental of Floating Production Storage & Offloading (FPSO) facilities. TBA wells are produced through well–to-well gas lift. This method can increase the daily production of TBA field. In addition, the use of gas lift to minimize pressure loss along the wellbore can extend the life of the well and increase the cumulative recoverable reserves. Thus, this field is more soundly in economic for reactivation.
This paper will concern on how to reactivate the two wells in the TBA field by considering remaining reserves, recovery factor, production forecast, optimizing gas lift operation, and economics. To be more fruitful, sensitivity for FPSO daily rental cost and oil price will be added in the discussion part.