bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Mapping while Drilling in Vuggy and Heterogeneous Carbonate Reservoir - A Success Story from East Java Basin
Authors: Muhammad F.. , Othman T. R. , Pujiriyanto A.. , Setyadi A. L. , Ardikani N.. , Azwar O.. , Pasaribu I. T. , Permanasari D.. 
Published: October 2017

Abstract
Carbonate reservoirs in East Java basin had been known for its challenging drilling conditions due to the overlying shale instability and heterogeneity. The primary carbonate formation in the field has multiple reservoir targets with different flow units, which are dominantly due to secondary porosity resulting from karst processes. These reservoirs are relatively thin with net thickness ranging from 10 to 40 ft. Thus, the amount of producible hydrocarbon will depend on the length of the drain section along the reservoir. Horizontal well was selected by the oil operator in order to have economical production rate from each of these carbonate reservoirs.
However, there are high uncertainties on the structural dips along the planned lateral length due to limited numbers of offset wells and low seismic resolution. Moreover, karst has irregular shapes and sizes that can pose additional challenges such as directional drilling control, loss circulation, and deep mud invasion that affect shallow measurements. Technology with deep directional measurements that is capable to map the reservoir boundaries and structural dipping beyond the karst zone, is therefore required to achieve the horizontal length objective. This paper highlights a successful horizontal well placement in a karstified carbonate layer utilizing the new LWD reservoir mapping technology, in conjunction with the other LWD measurements that provide the necessary petrophysical information for thorough reservoir evaluation. This new deep directional electromagnetic technology extends the depth of investigation to 100 ft or more from the wellbore and resolves multiple layers with contrasting resistivity, for reservoir-scale imaging capability.
As a result, the lateral drain section was maintained successfully in the target reservoir with total net length of ~2600-ft. This interval consists of 45% length in karst or secondary porosity and 55% in the matrix-dominant porosity. Multiple layers with depth of investigation up to 50 ft were mapped in the inversion result from Reservoir Mapping-While-Drilling technology, where top and bottom reservoir boundaries were continuously mapped during drilling. In addition, reservoir mapping application in this well revealed the various heterogeneity natures in the reservoir such as lateral changes due to karst system diagenesis process and a sinkhole feature. These informations are useful for improved reservoir evaluation and delineation.
The integration between reservoir-scale imaging and the geological concept of the field not only has the capability to map the reservoir boundaries and structural dips around the trajectory, but also led to optimum steering decision. Following the success, similar method and technology will be used in the subsequent horizontal wells in this field.
A Cable-Controlled Pressure Testing Technology for Separate-Layer Production
Authors: Qinghai Yang , Shujin Zhang , Yaning Liang , Qingfeng Yue , Renyong Liu 
Published: October 2017

Abstract
The separate-layer production system is usually used to solve the problems of low separate-layer control level, difficult water locating and plugging, high operation cost and low testing and adjusting efficiency. This paper proposes a cable-controlled pressure testing technology for separate-layer production. Through the interworking of adjustable production regulator, pressure measurement instrument, ground control host and fishing tool, the separate-layer pressure measuring can be realized. The pressure measurement instrument consists of releasing unit, two pressure sensors, electrical setting & releasing mechanism and control circuit. Due to the dimension restraint, the traditional mechanical releasing way is not suitable. Therefore, the electrical releasing unit is designed and the lead limit switch is applied to guarantee accurate releasing. The setting & releasing mechanism possesses double leather cups which adopts the combination of mechanical compressing and hydraulic dilating to improve the sealing reliability. Two independent pressure channels are employed for formation pressure and oil tube pressure, respectively. The pressure measurement instrument is run into the wellbore through annular by cable. When the meter is set with regulator, ground control host orders the controlling motor to release the meter. Then, on-board controlling circuit unpacks the leather cups to establish the pressure channel between individual formation and the pressure measurement instrument. After about 5 days, the pressure build-up curve of the formation can be achieved. The specialized fishing tool is run into the separate-layer production string to locate the pressure measurement instrument with the help of centralizer and guide mechanism. The releaser is captured with the fishing tool and the pressure measurement instrument is fished. In the oil immersion test, the leather cup showed excellent sealing in diesel oil under 50 Celsius degrees and 15MPa for 90 minutes. The measuring range of the pressure measurement instrument is 0-40MPa and the accuracy is 0.05%. The cable-controlled pressure testing technology realizes measuring of individual layer and is characterized by high accuracy, small diameter and fishing. During the testing, only the production of measured layers is suspended, with no influence on other layers. Field tests showed the maximum pressure difference of 2MPa between individual layer and full wellbore, which identified the necessity of separate-layer testing.
Benefit of Better Understanding by Production Logging Tool: A Case Study of A Malaysia Reservoir
Authors: Hutamin Nurhidayah , Yaakob Amirul Afiq , Sa'aid Hasanah , Salleh Nor Hajjar , Nor M. Hafizuddin , Anas W. M. , Setiawan Agus , Rahman M. Zhafran , Iless Nur Afifah , Azwan M. Hafiz , Chun A. Kok , Mohamed Tatmimiddin Alhasani 
Published: October 2017

Abstract
Fault Block M is a reservoir package consisting of three major sand layers, A, B and C, with C being the best sand in terms of reservoir properties and continuity, followed by B and A. Fault Block M was developed with water injection through commingling of eight oil producers and three water injectors. In 2012, five more wells were drilled to improve reservoir recovery. In view of a fresh reservoir understanding, the team embarked on a full scale data acquisition including quarterly pressure survey and production logging campaign in 2015 and 2016 to determine sands layer pressure and flow distribution for both producers and injectors. Based on better reservoir understanding, many replications of low cost water shut-off have been conducted, which resulted in the field achieving its highest daily production since the infill campaign in 2012. The ratio of data acquisition and well intervention costs to revenue gain has proven to be low, a perfect production enhancement solution for the current low oil price scenario.
This paper reviews how production logging tool helps in reservoir surveillance and production allocation. While commingling production and injection is cheaper in development sense, commingling sand of difference in quality should be done with great care and strategy. While chasing the barrels, periodic data acquisition is crucial thus shouldn't be neglected to ensure correct understanding of production behaviour and RMP requirement.
Review of 20 Years Hydrocarbon Gas Cycling in the Arun Gas Field
Authors: Suhendro Suhendro 
Published: October 2017

Abstract
Lean gas injection in gas field is a good alternative to maintain reservoir pressure, minimize the condensate banking near wellbore and to mitigate the oversupply operation during low market. In this study, past gas cycling operation was examined to see the operability aspects and subsurface implications.
The Arun gas field was found in 1971. A 10,000 ft depth gas-condensate reservoir was found to have 503 ft thickness in average and 21,450 acres area with 7100 psig initial pressure and 352°F. Initial condensate-gasratio (CGR) was 50 bbl/MMSCF. The reservoir has 16.2% average porosity and initial water saturation (Swi) of 17%. Volumetric original gas in place is calculated to be 17 TSCF (excluded impurities). Baong shale underlain reefal carbonate of Arun reservoir is identified as the cap rock. Cumulative condensate production is 846 MMSTB. Approximately 5 TSCF (30% OGIP) had been recycled during 1977 – 1998.
Not many gas fields in the world with gas recycling had achieved 95% recovery factor. This paper will deliver the results of gas cycling, i.e. delay reservoir pressure decline, and maintain CGR and economic improvement of this field. Surface facilities and operation aspect will also be elaborated. Production and pressure data show that gas cycling indeed contribute to the improvement of field recovery factor and economics.
This paper should help the development of other new gas fields especially for carbonate gas reservoirs. The successful gas cycling in Arun field will encourage other gas field operators to implement the same methods.
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.