bluuebunny/crossref_metadata_2025 huggingface dataset:
Maximising Production of Low Injectivity Steam Flood Reservoir through Pressure Balance Approach
Authors: Pasaribu Rinaldi , Roma Rony , Wicaksana Yana , Muharam Cece , Aksehirli Attila
Published: October 2017

Developed in 2013, The Duri Area-13 steamfloodcovers a total of 145 patterns. Patterns are developed as inverted seven spot with 5.5 acres spacing which is the smallest pattern size in the Duri field. Steamflood was started in April 2014 with a single sand target. After 2 years of injection, the production response was less than forecasted, predominantly caused by low injectivity and inefficient drainage.

Steamflood management in Area-13 is quite complex since the zone of interest has lower sand quality compared to the analog areas. Increasing the injection rate has been a challenging task to perform. Most patterns are injecting at 100-250 BSPD at the maximum wellhead injection pressure. This is far below the target injection rate of 800 BSPD. Injection of steam at a low rate is likely to cause steam chest collapse before it reaches the edge of the pattern. Heat losses during steam propagation will reduce steam enthalpy to a liquid phase value. The presence of liquid phase may lead to reservoir pressure increase which causes further injectivity problems.

A pressure balance strategy was initiated in early 2016 to solve this low injectivity problem. Pressure depletion after production withdrawal is promptly balanced by increasing injection. The initiative consists of an integrated effort between production and injection including an aggressive huff & puff strategy, vigorous injector wellhead pressure monitoring and injection optimization.

The initiative has proven to be successful in improving the performance of Area-13, with production and injection ramping up significantly. Current production is higher than the 2017 forecast. The initiative also proved that implementation of a pressure balance strategy between withdrawal and injection could significantly improve injection of a low injectivity steam flood reservoir.
Delivering an Effective and Efficient Contract Transfer in Manpower Contract Management to Maintain the Stability of Daily Operation
Authors: Meiraharyanti Astri , Hidayatullah Aulia S. , Kusumasari Novita
Published: October 2017

During transfer process in manpower contract management, communication issues may appear and affect the involving parties. It is not merely happened within internal company, but also with the contractors who shall provide the services and the manpower contract personnel as subject of transfer. Contractors, both the incumbent and the future employer, shall provide clear information to the personnel related to their employment including all administration matters. Improper communication to the personnel may lead to personnel's anxiety and confusion which then influence their performance in delivering services to company. The present work explains a success story in Total E&P Indonesie (TEPI) where transfer process could run smoothly and disadvantage situation in industrial relation aspect could be avoided. Coordination and communication among parties become one of the key areas which support the process. In order to achieve the objective, a set of timeframe, strategy, and guideline explaining the responsibilities of each party involved in the handover process shall be produced as reference. Implementing proper handover strategy could minimize the potential industrial relation dispute and maintain the operational activity in which personnel may think that business is run as usual without any change. With active participation from all parties to follow the set strategies and guideline, handover contract could be delivered timely with minimum issues and dispute.
Stimulated Reservoir Volume of Multi-Stage Fracturing in Horizontal Shale Gas Well: Modeling and Application
Authors: Lin Ran , Ren Lan , Zhao Jinzhou , Huang Jing
Published: October 2017

For the multi-stage fracturing in horizontal shale gas well, the stimulated reservoir volume (SRV) is a pivotal parameter to determine the fracturing performance. However, SRV estimation remains a longstanding challenge in shale gas reservoir due to its complex forming mechanism, most of the current SRV estimation methods are either expensive or time-consuming. In this paper, a 3D mathematical model of SRV is established by simulating the four key processes—multiple hydraulic fractures propagation, reservoir pressure lifting, formation stress variation and natural fractures failure—during each fracturing stage in shale gas reservoir. This model considers the interference effect of multiple fractures, and subdivides the SRV into shear-SRV and tensile-SRV according to the failure type of natural fractures network. In order to validate the feasibility and reliability of the model, it was first implemented to a pilot well in the FL gas field in southwest China to estimate a SRV that matches well with the microseismic signals monitored onsite. Then, this model was applied to FL gas field on a large scale, the application results show that although most horizontal wells have been effectively fractured with desired SRV, there are still unstimulated regions left between neighboring wells, so it needs to drill infill wells in current well pattern and reduce the well spacing in the future. This research explores an efficient method to estimate the SRV without high cost or complicated process, provides the theoretical basis and guidelines for pre-fracturing design and post-fracturing evaluation in shale gas reservoir.
Advanced Methods for Determining the Value of Information of Surveillance Data Acquisition Using Predictive Analytics
Authors: Kechut Nor Idah , Hassan Abd Azim , Izyan Wan Fatin , Zamri W M , Raub Mohd Razib , Tewari Raj Deo , Kuzmichev Dmitry N. , Mironenko Yulia , Buoy Rina , Alessio Laurent D.
Published: October 2017

In stacked reservoirs with commingled production, achieving an understanding of relative contributions of the flow units is fundamental to reservoir management, most notably for conformance management of reservoirs under water flood or enhanced oil recovery (EOR) scheme.

To that effect, the desired surveillance data usually includes: reservoir layer pressures, phase distribution profiles (through PLTs) in flow units, and monthly well test data (water cut, gas oil ratio, oil rate etc.). These measurements will form the basis of well by well flow unit production allocation; all necessary information for classical engineering analysis and reservoir simulation.

The enduring challenge of value-effective reservoir management is to determine the ‘adequate’ frequency and selection of well and flow units data acquisition. Industry practice shows clearly that there is no consistent answer to this challenge. In the authors' opinion, this is due to the unavailability of a methodology and tools to rigorously define the Value of Information (VOI) associated with surveillance data acquisition. VOI is defined as the net present value (NPV) difference between the total production & costs outcomes with the benefit of information, and the total production & costs outcomes without this information. In some cases, the VOI can also indirectly translate to critical understanding of subsurface integrity such as unintentional communication of deeper, higher pressure gas reservoir with shallower reservoir units having a much lower fracture gradient that if left unattended could subsequently lead to subsurface blowout scenario.

In this paper, we set out to define surveillance data acquisition decisions as an optimisation problem: where is the optimum cost versus reward for a field, given allocated well production and the usual (partial) understanding of reservoir layer absolute and relative permeability at the well, from logs and core.

We present how novel predictive analytic algorithms, coupled with multi-phase deliverability models, material balance analysis, and global optimisation search methods are integrated to assess the resulting uncertainty in layer-phase allocation, in presence of different surveillance datasets. We use a representative synthetic field simulation model to formulate reservoir outcomes.

As a precursor to a full VOI, we define an allocation uncertainty versus the data acquisition frequency, and provide general recommendations in terms of data frequency and type that can be generically used as findings.
Quantitative Assessment of Preferential Weld Corrosion in Operator Supplied Weight Loss Coupons Using White Light Interferometry
Authors: Leahy Michael , Cook Stuart , Mok Wai Yeung
Published: October 2017

A recent corrosion inhibitor recommendation for a low water cut gas condensate line was conducted by the use of weight loss measurements aided by the use of white light interferometry. Weight loss was studied using a standard rotating cage methodology. To assess localized attack on the coupons both as pitting and preferential weld corrosion (PWC), white light interferometry was utilized and the 3D scans that were produced were then used to assess both tendency for pitting corrosion as well as the depth of attack across the weldment regions.

Machined coupons from the pipeline material were provided by the operator to a set geometry to be used in a rotating cage apparatus. After preparation for corrosion testing, the coupons were prescanned then exposed to both inhibited and chemical-free synthetic fluids for periods of 120 and 500 hours. The tested coupons were then cleaned of corrosion products and rescanned using interferometry to assess any corrosion that had occurred.

From initial pre-test coupon geometries, the average weight loss results, and the depth of attack, individual corrosion rates for the weldment regions were calculated to assess the PWC in a complementary manner to using electrochemical techniques for determination of PWC. In addition to corrosion rate data, 3D profiling allowed visual assessment of preferential weld attack that is not possible using segmented weld electrodes, where individual electrodes are isolated and material lost due to the machining process. Evidence of localized corrosion in the form of pitting was captured across the weight loss coupon during the scanning process.

The technique allows for the following: Examination of whole weld sections with no material wastage between metallurgical zones during coupon machiningCollection of supplementarydata to compare to electrochemical testing of weldsProviding greater power for spatial assessment of PWC from 3 dimensional interferometry images

This paper discusses the white light interferometry technique and results in detail, as well as demonstrating the pros and cons to utilizing non-destructive measurements, when compared to existing methodologies, for assessing localized corrosion.
Customization of Fit for Purpose WBM Opens New Opportunities for Significant Cost Savings, Well Construction Optimization, and Environmental Footprint Reduction
Authors: Ghamdi Muataz S. , Saleh Rami F. , Yami Fahad M.
Published: October 2017

An approach of developing customized WBM system to overcome shale related problems is discussed. The system has been developed for drilling shales in water aquifers where no OBM can be utilized, and for offshore and remote field operations where the cost of transportations and logistics of OBM is substantial.

In a case study of a remote onshore field, the shale causing the majority of the wellbore instability issues was cored. Lab tests such as X-ray diffraction, cation exchange capacity test, and shale erosion test were performed on the core samples. Based on the testing outcomes, a specialized inhibited water-based fluid formulation was developed to counter-act the studied shales. After the analysis phase was completed, the implementation phase was initiated to measure the effectiveness of the developed system in overcoming shale related troubles.

The first implementation aimed to pilot test the developed drilling fluid ability to stabilize the shales encountered in the troublesome section. The customized mud drilled the section successfully, providing comparable wellbore stability experienced with oil-based system normally utilized to drill. This implementation demonstrated that OBM usage in the remote field can be eliminated, saving the cost of logistics and transportations. The second implementation was performed to simulate the capability of re-entering wells that were constructed following an older casing design. Because of the wellbore instability challenges, these wells were deemed impossible to workover. The developed mud was utilized to successfully sidetrack a well and drill through the shales and underneath gas cap to target entry safely, proving this system can be used to re-enter these wells and tap into their production potential, saving the cost of drilling new ones. The third implementation targeted the optimization of casing design by combining sections. Since the wellbore instability issues could be controlled with the customized system, the casing normally set to shut off the troublesome zone could be extended to target entry. The trial test of this concept was successful. Resulted savings include eliminating the liner installed in the standard well design, saving rig days, and eliminating expandable liners in future re-entries.

The deployment of the developed system has resulted in significant cost savings, allowed for more operational efficiency, enabled more optimization in casing design and future re-entries, and reduced the environmental footprint of drilling operations.
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

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

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

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

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

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

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

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

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

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

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.
Ultra-Low-Invasion Fluid Technology Increases Operational Window to Enhance Drilling, Reduce Damage in Unstable Venezuela Formations
Authors: Herdes Miguel , Aguilar Katiuska , Fernandez Daniel , Garcia Jose , Moreno Jose , Maldonado Reinaldo
Published: October 2017

Historically, the well documented diversity and complexity of formations throughout Venezuela have severely complicated the design and engineering of drilling fluid systems capable of maintaining the wellbore stability required to maximize drilling efficiency and reduce formation damage. Producing formations in Eastern Venezuela, are typically low-pressure consolidated sands with elevated bottomhole temperatures and differential pressures ranging from 3,000 and 7,000 psi.

This paper describes the technical development and subsequent application of an ultra-low-invasion drilling fluid additive, designed to deposit a thin, impermeable barrier over the pores and microfractures of weak, under-pressured and otherwise troublesome formations, to maintain wellbore stability and reduce formation damage. Three case studies will be presented to demonstrate the effectiveness of the technology to prevent differential sticking and other wellbore instability issues, minimize fluid-related non-productive time (NPT), increase overall drilling efficiency, and reduce operating costs.

Validated in 14 wells, the operating window of the Naricual Formation was expanded appreciably due to the use of the ultra-low-invasion drilling fluid technology. It was also demonstrated that stability was maintained in the open hole with 7,000 psi of differential pressure at 16,810 ft, which allowed an optimized well design that eliminated one casing section. The wellbore stability was confirmed with wireline pressure-point log measurements. Furthermore, through direct offset comparisons, the authors will detail significant improvements in wellbore stability and the subsequent prevention of losses and differential sticking in a different field, where more than 1,000 bbl of losses had been recorded across the Miocene and mid-Eocene sediments.

Moreover, core tests results will illustrate the efficiency of the thin, but tough filter cake, to prevent the invasion of drilling fluid into the formation matrix, thereby minimizing formation damage down to 4.5% (95.5% retained permeability). Thus, the original structure of the formation is preserved, effectively preventing formation collapse, differential pressure-induced crossflow across open zones, and importantly, pay zone contamination.
Centrifugal Pump and Centrifugal Compressor Process Containment
Authors: Muthanandan Sundralingam
Published: October 2017

Centrifugal Pumps and Centrifugal Compressorsare classified as driven equipment which are widely used in the oil and gas industry. They are primarily used to boost the operating pressure and transfer liquid and gas respectively in a safe and reliable manner. Process containment is one of technical integrity and safety barrier classified under Safety Critical Element (SCE). Various components such as casing, gaskets and mechanical seals and dry gas seal were discussed, threats and possible damage mechanism and improvements were shared.

Basically, the mechanical seal by design is not a positivesealing like static flangetoflange connection, but rather has always had some acceptable leakage. The question of "how much leak is acceptable" was tested at site, the results analyzed and compared for safe operation. Leading damaged mechanism such as presence of liquid in the DGS in centrifugal compressor application were also discussed.

Lessons learnt related to early failures due to seal, seal cooling system, maintenance practices for correct seal installation post repair works were discussed. Besides that, damage mechanism from the contaminants such as sand in the product and damages tocasing and seals due to erosion and impingement were also discussed. Condition monitoring techniques that can be employed for reliable operation of the pump and compressor seals were also discussed. The article also describe some of the best practices that could improve the reliability of seals.
Low pH and Salinity Induced Wettability Modification of Hybrid EOR as Polymer-Assisted Carbonated Low Salinity Waterflood in Calcite Cemented Sandstone Reservoir
Authors: Lee Ji Ho , Kim Gwan-woo , Lee Kun Sang
Published: October 2017

Hybrid polymer-assisted carbonated low salinity waterflood (PCLSWF) modifies both oil and brine viscosities and wettability in calcite-cemented sandstone reservoirs. In core- and pilot-scaled systems, PCLSWF increases ion-exchange of Ca2+ modifying reservoir wettability toward to water-wet condition. In the process, dissolved CO2 in brine is transferred into oil. The interphase transport reduces both oil viscosity and density. As well, the dissolved CO2 in brine reacts with water and produces H+ in brine. This low pH of PCLSWF dissolves calcite minerals and provides Ca2+ into brine resulting in increased ion-exchange of Ca2+. Due to significant mineral reaction rate in pilot-scaled system, enhanced wettability modification by mineral dissolution is observed in pilot-scaled system rather than core-scaled system. In addition, PCLSWF increases the viscosity of displacing fluid. Though it undergoes mechanical degradation and slight chemical degradation, it is still effective to improve mobility. The improved sweep efficiency of PCLSWF allows injecting fluid to flow in less permeable area. In heterogeneous pilot-scaled reservoir, the combined effects of PCLSWF enhance oil recovery up to 12%, 6%, and 2% over low salinity waterflood (LSWF), low salinity polymer flood (LSPF), and carbonated low salinity waterflood (CLSWF). Optimization process maximizes the efficiency of PCLSWF and has recommended to deploy PCLSWF with CLSWF preflush. The optimized injection design of PCLSWF increases NPV up to 18% more than LSWF.
Predicting Start-Up Liquid Loading in a Mature Oil & Gas Field: A Case Study
Authors: Malik Ankit , Prakash Ravi , Kumar Mukesh , Barot Miten
Published: October 2017

Liquid loading of oil and gas wells occurs when the reservoir fails to deliver hydrocarbons to the surface due to accumulation of liquid in the well. In Oil reservoirs with gas cap and aquifer, liquid loading post shutdown revival of oil wells with high gas liquid ratio (GLR) is poorly understood and documented. The mechanism and prediction of onset of such liquid loading has been studied and discussed in this paper.

The field observation of loading of high GLR oil wells could not be explained with steady state analysis in a mature carbonate offshore field. Transient analysis successfully revealed liquid loading as observed in field. However, correct set up of initial conditions is imperative for prediction using transient analysis method which is discussed in this paper. A workflow has been developed to predict onset of start-up liquid loading and to build in risking using a risk matrix incorporating relevant well parameters. The methodology was used to estimate the gas lift requirement and associated risked reserves.

The liquid loading of high GLR oil wells after a brief period of shutdown has been successfully modelled using transient method by representing correct initial conditions. However, ability of well to re-deliver gas at the steady state GLR value during the start-up is an uncertainty. Hence, an element of risking has been captured to predict the most likely time of start-up loading using a risking criterion based on individual well's flow parameters.

The results from the above methodology of prediction and risking show that wells are susceptible to liquid loading much in advance as predicted from steady state workflows which matches with the field observed well performance. This has a significant impact on the lift gas flowrate and top side infrastructure required to sustain flow from these wells. The paper also discusses a strong business case to evaluate liquid loading from predicted parameters at field development planning stage using the proposed workflow to secure future well production and save on additional costs of retrofitting gas lift infrastructure.
Small is Beautiful: Why Small Fields are the Next Big Thing in South East Asia and How to Capitalise on Them
Authors: Volkenborn Arnold , Lea-Cox Andrew , Sun Bo
Published: October 2017

Since the 1990s, most countries in SE Asia have been challenged to meet domestic demand using their own petroleum resources. To date, most easy-to-produce resources have been developed, leaving SEA with dwindling reserves and more technically challenged resources in small/marginal and deepwater fields. The average size of discoveries in SEA has decreased to ~35 MMBOE from double or triple that in the 1970s-1990s. Conventionally, small fields (<100 MMBOE reserves) are riddled with operational and economic challenges. The low oil price environment further exacerbates the resulting poor margins. Exploration and production (E&P) companies have been cutting spending and refocussing their portfolios on core areas of advantage.

In these increasingly challenging & uncertain times for the industry, we show how a new approach to small fields could unlock more than twice the NPV of larger conventional fields in SEA for a similar size of capital expenditure (capex).

Capturing this value though, will require a fundamental step change in operating model of operators. The Small Fields approach focuses on margin maximisation, instead of recovery and productivity maximisation. This means (1) targeting easy sweet spots (at the play and reservoir level); (2) establishing a blowdown-style investment baseline; and (3) selectively investing in incremental projects against this baseline.

Players who adopt this strategy will need to be lean, fast & agile, with an organisation and commercial construct that may more closely resemble a technology start-up than an E&P company. This will be a radical shift in mindset for most E&P companies and especially for National Oil Companies (NOC). But for many Asian countries, this may be the only option to maximise the returns and economic benefits from their hydrocarbon resources before it’s too late.
Advantages of Insert Pump Application through Tubing in SF Field Shallow Reservoir
Authors: Astuti Helmy Rina , Ernata Wayan Mahendra , Prasetya Afriandi Eka
Published: October 2017

"D" Oil fields is one of the largest operating steam flood injection in the world, Steam Flood "SF" project, to pump heavy oil from the relatively shallow reservoir. "SF"s peak production ever recorded at 2 Billion BPD in year 2006. SF project has 13 areas with over 5,000 oil wells production using artificial lift system. Nowadays, SF oil was declining due to natural processes so it will produce less than its peak production.

SF Area were commonly use Subsurface Rod Pump Manifold Tubing Pump, the pump unit as a whole system were set with tubing into the well, where the barrel attached to the lower end of the tubing, and the plunger along with traveling valve is connected in lower end of the sucker rod string. When the pump be pulled then both the rod and tubing should be pulled together. Tubing pump are usually easier to be applied for shallow wells with small productivity.

Currently in SF operates well producers using regular Tubing Pump where only less than 30% of them being produced with optimum fillage and most of them (60%) categorized as low fillage. The low fillage wells are potentially increase with increasing number of well with low productivity (matured Area). Management captured one of alternatives in order to improve number of optimum fillage wells and to increase the pump efficiency by utilizing Insert Pump (not familiar in SF) which is expected have some benefits for low rate wells (below +/-400 BFPD). Which from other project have successfully trial and proven delivered with 10 wells exceeded the previous life span, improved pump efficiency to 37% and reduce >20% RS job cycle time which contribute around 3.7 $MM.

Novelty, the success ratio of using the insert pump was proven by increasing pump efficiency up to 37%; life span of pump unit much longer than usual; Reduce OPEX and increase production by minimizing Loss Production Oil.