bluuebunny/crossref_metadata_2025 huggingface dataset:
Large Capacity Data Microchip Transmission System and its Opportunities
Authors: Gramajo Eduardo , Li Bodong , Li Sanguo , Zong Yanbo , Rached Rached Maurice , Tella Sherif Adekunle , Zhan Guodong
Published: February 2023

Downhole data transfer has been limited by slow downhole communication bandwidths for decades. The current data-transferring technologies have reached bottlenecks for acquiring logging data and ever-demanding high-frequency drilling dynamics measurements. There is an urgent need to significantly improve the downhole data communication speed for drilling optimization, real-time geosteering, and reservoir description. Current downhole communication systems with data rates between 20bit/s – 60kbit/s are not sufficient for the above-mentioned applications, let alone their limited robustness in structural integrity against inherent environmental noises and low cost-effectiveness make them less efficient. Therefore, a new downhole communication system using data microchips is proposed in this paper.

The paper presents the improvements made to the first version of the data micro-storage-balls MSBs (Li et al., 2022) to adapt the system to 1) more complex drilling projects and 2) the acquisition of high-resolution and large datasets in a quasi-real-time for better well management decisions.

The presented technology can transfer large amounts of data without needing a specific drill pipe connection or structure and employs the basic concept of a "flash drive" (downloading and exchanging data among systems). The equipment achieves time-devised data transmission using microchips stored in a sealed chamber which are released using a standard BHA sub. The upgrades to the first-generation MSB (larger memory capacity, robust packaging material, and added sensors) will improve multiple aspects of the technology. 1) The capability of deploying them in long horizontal sections and the recovery rate due to efficient housing density management (≤ 1.5 g/cm3) using high-performance hollow glass beads. 2) The increase in storage capacity (up to 32Gbit) with the use of state-of-the-art circuit boards that also support higher temperatures and pressures, improving the storage capacity, transmission rates, and overall tool performance in deep reservoir locations. Therefore, the newest additions and modifications made to the first generation of MSBs can create remarkable performance improvements.
Novel Approach of Autonomous Drilling Using Rotary Steerable System in Middle Eastern Oil and Gas Wells
Authors: Oliveira Victor , Elsadig Mohammed , Al-Ghazzawi Ayman , Osman Ahmed , M. Al Dossary Abdullah
Published: February 2023

The history of wellbore trajectory control can be traced back to the days of drilling with rotary assemblies. During that time, experienced directional drillers (DDs) used their knowledge about the response of bottomhole assemblies (BHA) in a specific area or field by means of drilling parameters and assembly configurations changes. This method required intensive field and human experience and still resulted in considerable deviations from the required trajectories. Technologies evolved with the introduction of motor and rotary steerable systems that have additional predicted directional responses, however, considerable human intervention was still required to control the trajectories. As the rotary steerable system (RSS) tools matured, entire sections of the well trajectories were automated with closed-loop trajectory control that required minimum human intervention. However, the curved sections continued to be drilled in manual modes with DDs interventions.

A major operator focused on evaluating and validating a novel approach from its major directional drilling service provider using the auto-curve drilling mode to automatically drill the curved sections without human intervention and complete the missing puzzle of the autonomous well construction. The system is based on a minimum curvature method, which updates the target inclination and azimuth in a closed-loop system, similar to the one used in the hold inclination & azimuth method. Expected run rate of penetration (ROP) and planned dogleg severity (DLS) are needed while programming the tool for the RSS calculation update. Once the auto-curve mode is engaged in the RSS tool, updating the target inclination and azimuth will continue along the well to deliver the programmed DLS as per the ROP input.

A detailed comparison of the measurements has been performed through three directional drilling curve sections in three wells. Combining the data of the three wells, 5,632-ft were drilled in different sections. The results were promising and showed an average of 70% reduction of human intervention. Furthermore, regarding the well positioning, the new auto-curve automation technology delivered the wells within the required profile target tolerances with minimum tortuosity.

The novel autonomous curve drilling technology helped to minimize human error, enhance the accuracy of well positioning, and improve hole quality for drilling and workover operations. The system proved that this autonomous drilling technology is capable of improved well trajectory delivery with minimum intervention, faster well delivery, and reduction in operation costs.
The Proper Well Spacings – A Supplementary Method to Maximize The Gulf of Thailand Development Project Value
Authors: Hotapavanon Pitchaya , Suyacom Kasinee , Chuachomsuk Korakoch , Thapchim Jiraphas , Nasomsong Rutchanok , Chaipornkaew Metsai
Published: February 2023

For The Gulf of Thailand (GoT) projects, the bulk of investment goes in drilling development wells and the financial return is depending on how much reserve is effectively tapped by those wells. To improve project economics, both optimizing the well placements to access hydrocarbon and minimizing the number of wells are required. This study shows how proper well spacing used in development well planning is defined using the understanding of reservoir connectivity ratio at a given well spacing.

Firstly, reservoir correlation panels of wells drilled within the same trapping fault were created and the reservoir connectivity ratio at a given well spacing were collected. Hence the cross-plot between various well spacing and reservoir connectivity ratio was constructed to establish relationship. New reserves were derived by new pay from the spacing-connectivity relationship and estimated ultimate recovery per metre (EUR/m). With the estimated reserves varied by well spacing, the proper well spacing can be defined by identifying the narrowest well spacing that yield new incremental reserves above economic cut-off.

More than 100 cross-plots from Arthit project were conducted by using the existing wells information, the results suggest that a relationship between well spacing and reservoir connectivity ratio is varying depended on trap style, fault strike, channel width & oblique angle and hydrocarbon column height. A new/share pay ratio template is now available to illustrate an expected new/share pay ratio at a given well spacing (ranged from 100 m. to 1,500 m.) in each HC pay unit and subsurface geological trend. From the result, new pay ratio is in the range of 45%-60% at the current well spacing (400 m.) of Arthit Project. Based on the economic justification of Arthit project, there is the opportunity to narrow down well spacing for being economically viable in the future.

The optimum well spacing together with an economic viability analysis in each project could be done efficiently. Shortly, the proper given well spacing will be proactively planned for both infill and new wellhead platform. The 2021 infill projects help to validate the current model, improve the prediction function and certainly narrow down those uncertainties for future development projects.

Development planning would benefit greatly from proper well spacing so that the optimum number of wells is known upfront so project planning could be properly managed. If tighter well spacing could be applied, more wells could be filled into existing platforms. Then the big investment on new platforms could be deferred. Moreover, this method can be also broadened to other projects where GoT development model can be applied to achieve optimum commerciality.
Holistic Approach to Determine the Fracture Propagation Pressure (FPP): Consistent Interpretation of Step Rate Tests Using Multiple Analysis Methods
Authors: Cobanoglu Mustafa
Published: February 2023

A Step Rate Test (SRT)‘s is frequently performed method used to accurately measure fracture propagation pressure (FPP) of a given geologic formation. The injection rates in the test are increased in steps from low rates below fracturing pressure to high rates above fracturing pressure, allowing each rate to stabilize, and noting the stabilized injection pressure for each rate. Then, as classic approach, pressure at the end of each injection step versus injection rate are plotted. The fracture propagation pressure occurs at the intersection of the two straight lines. Then main assumption of the classic approach is that there are "2 distinct different regions with constant properties (i.e. KH & skin)" during multi rate injection test and those regions are the one without "induced fracture" region and the one with "induced fracture" region (i.e. post frac region). However, post-frac region properties is not going be constant since fracture dimensions changes injection pressure.

Therefore, the purpose of this paper is; To explore the pitfalls of the classic approach (pressure versus rate) by including derivation of the mathematic model for classic approach;To develop/provide other alternative SRT interpretation methods: "Pressure Transient Analysis (PTA) – detailed skin analysis" and "PTA– fall-off analysis"To define a holistic approach using Multiple SRT’s Interpretation methods in order to determine the FPPTo demonstrate the applicability of proposed approach for several SRT cases

The proposed holistic approach was successfully applied to several SRT tests conducted in Brunei, commingled waterflood injector wells. Results showed that; Derived mathematical model demonstrated that "classic approach" is underestimating the FPP: Depending on the reservoir fracturing characteristics, expected 2 regions, which is the basis of classic approach, may not be fully developed. This was also demonstrated by actual SRT data.Classic approach might result in misleading FPP results: 2 out of 4 case has no definitive conclusive results up and there is up to 9 % error in FPP estimation (classic versus PTA approach)Classic approach even sometimes might not provide conclusive FPP results: 1 out of 4 case has no conclusive resultPTA approach (i.e. detailed skin analysis and/or prep & post-frac fall-off analysis) was successfully applied to estimate FPP pressure and it seems to be most reliable method since it has provided conclusive results for all cases.PTA analysis could be extended to determine the induced frac properties (fracture, the fracture length, width & frac properties)

Recommendations on how to perform a holistic approach for SRT analysis & how to verify the results with standard PTA approach is provided. In addition, since there is no analytical model for induced fracture (i.e. pressure dependent frac), adopted PTA approach using hydraulic frac modelling to make an estimate for frac length size is also presented
Establishment of a Workflow to Assess Pore Collapse Mechanics During a Series of Loading and Unloading Using Micro-CT Scan and Rock Mechanics Testing
Authors: Hamid Osman , Aljamaan Hamza , Altwaijri Mohammad
Published: February 2023

Characterization of the reservoir rock elastic and plastic behavior is essential to set a series of guidelines for reservoir management, especially during gas storage cyclicity. The reservoir rock is subjected to loading during injection and unloading during depletion. These procedures lead to increases and decreases in the magnitude of the effective stresses in the poroelastic media. The guidelines for the reservoir development should be set to operate the field within the elastic limit of the formation to ensure the undamaged permeability of continuous fluid flow in and out of the reservoir.

Based on these factors, there is a need to accurately measure the dynamic permeability and porosity by characterizing the pore space and pore throat collapse for the current and future injection and depletion operations. This invention will achieve this measurement through a series of alternating measures between a three-dimensional (3D) X-ray computed tomography (CT) imaging and triaxial testing. These accurate and actual measurements mainly come from core plugs testing.

The process starts (T1) by scanning the core plugs with high-resolution imaging technology to map pore space and pore throat. The samples will be subjected to the first step of loading and unloading during Thick Wall Cylinder (TWC) test using different axial and confining pressure. The samples will be imaged and then mapped in the pore space and pore throat at a time (T2), and these processes will continue for ten cycles of loading and unloading. The results will be interpreted and extrapolated to match the number of injection and depletion scenarios. The fluid flow will be numerically simulated at the pore scale using direct flow modeling within the pore space with the Navier-Stokes-Brinkman equation to evaluate changes in permeability and porosity.

Using these novel integrated processes presented by this invention, injection and depletion guidelines will be set for future operations; this methodology also can be used for oil recovery to ensure safe operations within an elastic limit to avoid permeability damage that will lead to safe, effective, and economical operational scenarios.
Study on Rotary Percussion Tool Parameters Optimization and Trial Test Evaluation
Authors: Yulin Tu , Li Bodong , Zhan Guodong , Rached Rached M. , Gramajo Eduardo
Published: February 2023

Drilling in hard and abrasive formation represents a major challenge due to the low rate of penetration (ROP). Rotary percussive drilling tools take advantage of both the shear action of drill bit cutters and axial percussion energy to increase the drilling efficiency. Such tools have shown a significant benefit in drilling efficiency enhancement, especially in air drilling with an air hammer. This study focuses on a fluid-type rotary percussive drilling tool development and application to address the significant drilling challenge in drilling hard and highly abrasive sandstone formations. A rock mechanical study is carried out to get the compressive strength and the internal friction of the hard and abrasive formation. Then, a 6-3/4 inch rotary percussive tool is designed and optimized based on a relationship between rock mechanics and the output energy and frequency of the tool. Next, the tool was thoroughly tested in the workshop, and the key parameters were acquired and compared with the design.

The tool was trial tested in a hard and abrasive formation dominated by fine sandstone and siltstone in the upper section and a softer formation below. The new 6-3/4 inch tool was run in the test well and drilled DV tools, cement, float collar, and float shoe, then penetrated the hard and abrasive formation. The hammer drilled 912ft with an ROP of 10.5 ft/h with a pure drilling time of 87 hours. The ROP increase is around 30% for the same depth and formation with less WOB and RPM. Drilling efficiency was increased in the top section with less WOB and RPM compared with the same formation and depth of an offset well section drilled with hybrid bits. The differences of the wells in the hard abrasive formation thickness, bit type, BHA, bits dull grading, and RPM are studied. The tool performance evaluation and lessons learned from optimization and trial tests are summarized. The future direction of this work is also discussed.
Mixed Preformed Particle Gel System for Water Shutoff in Fractured Carbonate Reservoir
Authors: Cao Dongqing , Almohsin Ayman , Han Ming , Al-Harbi Bader
Published: February 2023

Water shutoff from production well using particle type material is a great challenge due to the complex pressure and flow distributions near wellbore. A mixed preformed particle gel (PPG) system was developed to enhance the performance for water shutoff in fractured carbonate reservoirs. The PPG blocking behaviors in fractures and methods to improve the water flush tolerance were investigated. PPG strength dominated the water shutoff performances in fractures. PPG with medium to high strength showed better performance than other samples due to the well-adjusted properties in blocking and flush tolerance. For the selected PPG, 30 mesh sample showed the best blocking performance among single mesh samples from 20 mesh to 80 mesh in the fractured artificial metal plug. Using 30 mesh sample as base sample, the 30 mesh and 40 mesh mixture with weight ratio 2:1 produced highest pressure build-up in two-size PPG mixtures. Further increasing the particle size distribution by combining various particle size PPGs, the blocking performance was improved. An optimized combination of 30 mesh, 40 mesh, 50 mesh and 60 mesh particles with weigh ratio of 4:2:1:0.25 was developed. In addition, a fiber material, added in the PPG, significantly improved the water flush tolerance of the PPG pack. A particle size combination of PPGs mixed with the fiber material generated better blocking performances than the other combinations. This study provides insights on packing behavior of deformable gel particles in fractures with a practical PPG based system for water shutoff treatments.
Successful Development of the Deepest Oligocene Syn-Rift Sediment in the Malaysia-Thailand Joint Development Area: Is the Deeper Zone Our Future?
Authors: Setiawan Avidianto Suryo , Simatupang Martin Hendra , Rachmadi Arif , Apiwathanasorn Sippakorn , Moh. Said Samsul Bari
Published: February 2023

Field X, located in the offshore Malaysia-Thailand Joint Development Area (MTJDA), comprises multiple stack gas reservoirs with a combination of trap styles. This paper highlights the challenges and lessons learned in successfully developing the deepest Oligocene syn-rift sediment in the MTJDA, which was initially discovered by the one appraisal well drilled in 2010. A further comprehensive evaluation was performed to justify the deepening of development drilling in 2019 (as appraisal cum to development) and 2021-2022 (as infill wells) with promising results.

The discovery of hydrocarbon resources in the deepest Oligocene syn-rift sediment at MTJDA was part of an appraisal program by deepening the development well. The two wells discovered and proved the presence of multi-stack gas sands in this deepest section (3800-4000 mTVDSS). The clastic sediment deposits in a fluvio-deltaic system. The reservoir properties of this syn-rift sediment are better than the early post-rift sediment (early Miocene). The production test confirmed the initial gas flow rate of about 15 MMscfd. A comprehensive analysis was performed to evaluate a sizeable volume before more development wells were proposed for this deepest sediment.

The initial understanding of Late Oligocene syn-rift sediment was very minimal at the beginning of the project. One of the neighbouring well information suggests lacustrine delta environments based on core data. However, a fair-quality seismic amplitude shows a broader channel belt (over 3km width) which usually exists in the braided stream. In view of the two appraisals cum to development wells' successful discovery, more than five wells were proposed to penetrate this zone as a deepening target from the existing discovered zone. The fit for purpose well designed with a monobore concept, was selected. Upon completing the development drilling with denser well spacing, it suggests the discontinuity of blocky sand presence with multiple fluid contact (stratigraphic compartmentalization), which is usually found in narrower channel reservoirs at the deltaic system rather than the braided stream. The good reservoir properties observe from the open hole log, formation tester, and production test. The success story of these wells opens future opportunities to plan more deep well to develop Oligocene sediment, which prove to be a good hydrocarbon producer.

This paper updates the previous understanding of geology, such as the depositional environment, and the understanding of reservoir productivity of the Oligocene sediment in MTJDA. It also proved sizable reservoir quality with extensive lateral presence and good productivity. Hence, the company foresee a promising future from this deep reservoir to prolong its long-term development plan.
Research and Application of Big Data Production Measurement Method for SRP Wells Based on Electrical Parameters
Authors: Chen Shiwen , Deng Feng , Chen Guanhong , Zhao Ruidong , Shi Junfeng , Jiang Weidong
Published: February 2023

Well metering is an important part of daily oilfield management. For wells in a block, production metering can help reservoir managers fully understand the changes in the reservoir and provide a basis for reservoir dynamics analysis and scientific field development planning. For single-well metering, accurate producing rate can help oil well operators optimize the well production system, improve the efficiency of oil wells, and even discover abnormal conditions in oil wells based on changes in production.

In order to obtain accurate well production, over 300 SRP wells in an experimental area of an oil field in northeastern China are tracked and measured in this paper. Easily available continuous electrical parameter data (including electrical power, current and voltage) and real-time output of the wells were selected as training parameters. We separated the SRP well electrical curves and corresponding real-time production data into a set of samples by one-stroke time, and obtained a total of 200,000 valid samples. The production status of the pumping wells was classified by deep learning, and the electric curves were Fourier transformed to extract statistical features.

Then, we performed deep learning on these samples, using production parameters as input vectors and well fluid production as output results. Finally, good results were obtained by training and a model for calculating SRP well production based on big data was developed. The model was used to calculate the production of SRP wells in an experimental area of an oil field in northeastern China and compared with the actual production data. For low-producing wells with daily production less than 6 m3, the error of the model was less than 0.5 m3 /d, and for wells with daily production greater than 6 m3, the relative error of the wells was less than 10%, which met the expectation of managers. Compared with the methods mentioned in this paper, the currently used measurement methods, such as flowmeter measurement and volumetric measurement, have limitations in terms of instrumental measurement range and real-time measurement, respectively. In addition, both of these methods increase the construction cost of flow measurement systems.

The big data production measurement model provides operators with a method for optimizing the production system of oil wells and also provides signals for early warning of oil well failures. This method can help managers achieve cost reduction and efficiency increase. The processing and application methods of electrical parameters in this paper can also provide ideas for production prediction of PCP o ESP wells.
Research and Application of the Comprehensive Corrosion Prevention Technology for Offshore Thermal Wells in Bohai Oilfield
Authors: Wang Hongyu , Han Xiaodong , Wang Qiuxia , Zhang Hongwen , Liu Hao , Wang Cheng , Zhang Hua , Dou Peng , Wen Jia
Published: February 2023

Multi-component thermal fluid stimulation has been conducted in Bohai Oilfield for about ten years and at the early stage of the pilot, the corrosion of the thermal fluid injection tubing is severe with the existence of the oxygen and the carbon dioxide under high temperature conditions, which result in damage of the insulation tubing, increase of the production cost and even unwanted workover.

For solving the corrosion problem and extending the working life of the tubing, the corrosion mechanisms is researched and analyzed at the first place. XRD and SEM is applied for analyzing the corrosion product. The results show that the corrosion is mainly caused by the high temperature carbon dioxide and vestigial oxygen. The high fluid flowing velocity and variable inner diameter of the insulation tubing also accelerate the corrosion process. Then, further study of corrosion behavior and corrosion prevention technology are proceeded.

Corrosion behavior study is carried out through indoor experiment. The results indicate that steel corrosion rate would reach the maximum value at the temperature of about 80 centigrade. At low temperature range, the corrosion is mainly dominated by CO2, and at high temperature range, the corrosion is mainly dominated by O2. For O2 corrosion at the conditions of about 370 centigrade and 15MPa, if the O2 concentration is below 1000 ppm, the corrosion rate would be lower than 0.076mm/a and when the concentration reaches about 1%, the corrosion rate would rapidly increase to be about 2.38mm/a. Based on the analysis above, high temperature corrosion inhibitor is researched and selected. The inhibition efficiency of the optimized inhibitor could be higher than 90% which could meet the technical requirement for corrosion prevention. For further increasing the efficiency of the corrosion prevention, tubing with higher corrosion resistance is used. For the existence of the CO2 and O2 in the inner tubing during the injection process, the selected corrosion inhibitor is injected before the thermal fluid for forming the protective film at the inner side. And for the annular space, high purity Nitrogen which is higher than 99.9% is injected for lowering its O2 concentration.

Till now, the comprehensive corrosion prevention technology has been applied for field test for nearly 30 well times. The corrosion problem has been greatly solved, the corrosion rate is lower than 0.1mm/a and no severe corrosion occurs during the thermal fluid injection process. Its successful application would provide a guidance and technical support for the subsequent offshore thermal exploitation.
Rock Physics Applications on Seismic-Based Reservoir Characterisation of the Gas Fields, Offshore Malaysia-Thailand Joint Development Area
Authors: Boonyasatphan Prat , Akarapatima Thanyanat , Poonyachotwanich Yanika , Majikol Piyanuch , Taha Mohi Eldin Sami Mohamed , Diyana Hafit Husna , Abd Mutalib Mohd Al-Amin
Published: February 2023

The A-J gas field requires the next phase of the drilling campaign, and identifying the new targets is required. So far, target identification is based on anomaly detection of seismic attributes together with geological concepts. The new thorough rock physics analysis is conducted to get a better understanding of rock within the area and, therefore, a better attribute selection for target identification. The rock physics analysis provides an insight of rock properties within the area and reveals the relationship between rock and seismic. The analysis also provides a better understanding in terms of geology. The analysis has suggested that the reservoir can be properly identified by using the far-angle stack related attributes. This includes relative acoustic impedance (rAI) and an extended elastic impedance (EEI). Validation of the attributes to the well has shown that the two attributes can help identify and define the reservoir within the area better. And the newly identified target from the study resulted in a better well targeting.
Intelligent Prediction of Downhole Drillstring Vibrations in Horizontal Wells by Employing Artificial Neural Network
Authors: Saadeldin Ramy , Gamal Hany , Elkatatny Salaheldin , Abdulraheem Abdulazeez , Al Shehri Dhafer
Published: February 2023

During the drilling operations and because of the harsh downhole drilling environment, the drill string suffered from downhole vibrations that affect the drilling operation and equipment. This problem is greatly affecting the downhole tools (wear and tear), hole problems (wash-out), mechanical energy loss, and ineffective drilling performance. Extra non-productive time to address these complications during the operation, and hence, extra cost. Detecting the drillstring vibrations during drilling through the downhole sensors is costly due to the extra service and downhole sensors. Currently, the new-technology-based solutions are providing huge capabilities to deal intelligently with the data, and machine learning applications provide high computational competencies to learn and correlate the parameters for technical complex problems. Consequently, the objective of this paper is to develop a machine learning model for predicting the drillstring vibration while drilling using machine learning via artificial neural networks (ANN) for horizontal section drilling. The developed ANN model was designed to only implement the surface rig sensors drilling data as inputs to predict the downhole drilling vibrations (axial, lateral, and torsional). The research used 5000 data set from drilling operation of a horizontal section. The model accuracy was evaluated using two metrics and the obtained results after optimizing the ANN model parameters showed a high accuracy with a correlation coefficient R higher than 0.97 and average absolute percentage error below 2.6%. Based on these results, a developed ANN algorithm can predict vibration while drilling using only surface drilling parameters which ends up with saving the deployment of the downhole sensors.
Real-Time Rig Less Intervention with a Catenary Coiled Tubing System to Perforate the Long Horizontal Section of a Well, Offshore Brunei
Authors: Leong Azemi , Abd Rani Rudzaifi Adizamri , Azizan Yusri , Yusoff Khairul , Idris Syahiran , Lim Hong Chean
Published: February 2023

A horizontal oil development well offshore Brunei had unwanted gas zones needing to be isolated and its oil zones reperforated. Limited deck space, riser length, long gun length, and a long horizontal section posed many challenges for executing the operation using conventional methods. To overcome these, a customized perforation and detonation gun system was used for efficient and safe deployment into a live well with Coiled Tubing (CT) to reach the target depth along with a Real-Time (RT) CT system, allowing more accurate depth correlation for the plug setting and perforation.

A Solution to the limited deck space was developed using an integrated RT catenary CT unit, pumping, and flowback package. This setup allows most of the equipment to remain on the vessel while transferring only minimal items to the platform and keeping the capability of pumping and safely managing the flowback from a live well. An adjustment to the injector jacking frame was also made by designing an extension that would safely increase the height for the gun length to be deployed while remaining able to withstand any strong weather. Additionally, software simulations were performed to verify that the longest perforating gun could successfully be deployed in and out of the live well. Due to the long target interval needing perforated, a gun deployment system was selected to reduce tripping time instead of a more traditional section-by-section method. With a ninety-meter gun length deployment in a single trip for the longest interval, this deployment method saved twelves trips compared to the more conventional approach. Overall, considering three intervals to be perforated, this system eliminated a significant number of trips for the whole project. RT CT integrated with sophisticated and reliable sensors guaranteed depth accuracy during the correlation process. These sensors delivered RT Gamma Ray (GR), Casing Collar Locator (CCL), pressures, compression, tension, torque, inclination, and temperature, fulfilling the requirement of achieving accurate depth control and overall RT monitoring of downhole conditions. The electrical firing mechanism allowed a more straightforward and safer firing process than the alternative of circulating a ball.

This project marked the first successful operation to perforate more than two hundred and fifty meters of target horizontal interval with three long perforating guns. This approach saved twelve runs compared to the more conventional method, which also needs additional correlation runs. The customized solution demonstrates that critical operations in long horizontal wells in challenging offshore environments can be successfully and safely executed.
Innovative Formation Testing Methods to Enhance the Field Development Plan: a Case Study in South-East Asia
Authors: Nakatani Akira , Cartwright Anthony , Copp Jonathan , Khunaworawet Tanawut , Daungkaew Saifon , Phan Linh , Kieu Viet , Babu H. Jagdeve
Published: February 2023

In early 2010s, two gas and gas condensate fields were discovered in a South-East Asia Basin. The Field Development Plan (FDP) was approved to develop both. After drilling several wells, the operator encountered complex challenges: (1) lower permeability reservoirs (2) complex HPHT subsurface structures (3) fluid identification, (4) reservoir understanding and connectivity. Formation evaluation, especially formation testers were therefore crucial for better reservoir understanding, to de-risk the FDP and maximize future productivity of the field.

This paper will discuss formation evaluation and formation testing in this campaign which consists of more than 10 jobs. Firstly, proper pre-job design and planning was done based on reservoir fluid information and reservoir properties from the previous exploration campaign. Analytical and numerical simulation models were conducted to properly design the Formation Tester (FT) tool string: probe/packer types, pump rate, and displacement unit types. Later, logging operation procedure, real time monitoring, and communication protocol will be also discussed with lessons learned and best practices. This workflow has set another milestone for fit-for-purpose solutions to tackle the reservoir and operational challenges.

In this campaign, apart from a new discovery, based on Downhole Fluid Analyzer (DFA) technology, we surprisingly proved different fluids in the deeper reservoirs. In addition, we were able to address reservoir connectivity, the main uncertainty in their FDP. This paper also discusses several innovative methods associated with FT technology to reduce uncertainties in the FDP such as:

The FT selection to help obtain best reservoir data, even in the most challenging environments such as low permeability, uncertain reservoir fluids, HPHT, and complex subsurface structure. As no well test was planned, Interval Pressure Transient Test (IPTT) data was used to obtain zone permeability which was later used to calibrate petrophysical data and the dynamic reservoir model. The use of pressure and DFA data to understand reservoir connectivity. The comparison between DFA data and PVT lab results will be also discussed. The use of advanced reservoir simulation software to understand reservoir contact uncertainty and improve reserve estimation.

From this work, we have learnt that collaboration between different teams and disciplines is most important for this to be a smooth and seamless operation. Innovation and sustainability workflows are always possible to adapt in order to achieve good results even in the most challenging environments.
Innovative Formation Testing Methods to Enhance the Field Development Plan: A Case Study in South-East Asia
Authors: Nakatan Akira , Cartwright Anthony , Copp Jonathan , Khunaworawet Tanawut , Daungkaew Saifon , Phan Linh , Kieu Viet , Babu H Jagdeve
Published: February 2023

In early 2010s, two gas and gas condensate fields were discovered in a South-East Asia Basin. The Field Development Plan (FDP) was approved to develop both. After drilling several wells, the operator encountered complex challenges: (1) lower permeability reservoirs (2) complex HPHT subsurface structures (3) fluid identification, (4) reservoir understanding and connectivity. Formation evaluation, especially formation testers were therefore crucial for better reservoir understanding, to de-risk the FDP and maximize future productivity of the field.

This paper will discuss formation evaluation and formation testing in this campaign which consists of more than 10 jobs. Firstly, proper pre-job design and planning was done based on reservoir fluid information and reservoir properties from the previous exploration campaign. Analytical and numerical simulation models were conducted to properly design the Formation Tester (FT) tool string: probe/packer types, pump rate, and displacement unit types. Later, logging operation procedure, real time monitoring, and communication protocol will be also discussed with lessons learned and best practices. This workflow has set another milestone for fit-for-purpose solutions to tackle the reservoir and operational challenges.

In this campaign, apart from a new discovery, based on Downhole Fluid Analyzer (DFA) technology, we surprisingly proved different fluids in the deeper reservoirs. In addition, we were able to address reservoir connectivity, the main uncertainty in their FDP. This paper also discusses several innovative methods associated with FT technology to reduce uncertainties in the FDP such as: The FT selection to help obtain best reservoir data, even in the most challenging environments such as low permeability, uncertain reservoir fluids, HPHT, and complex subsurface structure.As no well test was planned, Interval Pressure Transient Test (IPTT) data was used to obtain zone permeability which was later used to calibrate petrophysical data and the dynamic reservoir model.The use of pressure and DFA data to understand reservoir connectivity. The comparison between DFA data and PVT lab results will be also discussed.The use of advanced reservoir simulation software to understand reservoir contact uncertainty and improve reserve estimation.

From this work, we have learnt that collaboration between different teams and disciplines is most important for this to be a smooth and seamless operation. Innovation and sustainability workflows are always possible to adapt in order to achieve good results even in the most challenging environments.
Sand Fill Clean-Out on Wireline Enables Access to Additional Perforation Zones in Gas Well Producer
Authors: Field David
Published: February 2023

An Australian operator wanted to explore options for wireline conveyed sand bailing in one of their offshore platform gas producing wells. The objective was to remove twenty-six meters of sand fill inside 9.625" production casing, with an internal diameter of 8.681". Due to the landing nipple at the end of the tubing, the minimum run-in-hole restriction of the production tubing string was 3.987".

To limit the number of clean out runs, the latest technology in e-line deployed suction tools with a 4.25" OD was chosen, which provided increased recovery volume over its smaller cousins, plus real-time surface control and monitoring. Because of the tool's overall diameter, the landing nipple also required milling to allow access. Therefore, a specially designed 4.412" mill bit was manufactured and run on a milling tool – a tool requiring tractor conveyance to provide weight-on-bit and counter the reactive torque.

As the well had low deviation, the subsequent clean-out toolstring was run standalone (without tractor). One of the key factors governing the feasibility of conducting this operation on e-line was the overall toolstring lengths, where the lubricator height was limited to approximately sixteen meters.

The e-line deployed milling technology – which produces a grinding action rather than cutting – successfully milled through the landing nipple and a ball catcher in four runs, thus increasing the internal diameter sufficiently to allow access for the clean-out toolstring. A well fluid column of about seven bar is required to enable operation of the suction tool. The clean out tool was configured with three bailer sections (seven max) for the first run, to determine sand recovery optimisation. Three different sizes of micron bailer filters are provided; prior knowledge of debris particle size is therefore advantageous. In this case, a slickline bailing sand sample had been recovered, which immediately aided filter choice. Seventeen bailing runs were conducted over five days (with the number of bailer sections increased to six), successfully recovering a total of 918 litres of sand, equating to about 2.4 tons. Ultimately, the process enabled perforation of two additional gas zones to increase production.

The e-line toolstring, consisting of six different sensors and robotic tools, made this a more controllable and inherently safer operation than coiled tubing methods, as well as having a smaller footprint with reduced environmental impact. Operational details, including job planning and lessons learned will be discussed in the extended abstract.
Rejuvenating Waterflood Reservoir in a Complex Geological Setting of a Matured Brown Field
Authors: Azman Mohd Fairuz , Tunku Kamaruddin Tunku Ahmad Farhan , Mohmad Nis Ilyani , Zulkafli Luqman Hakim , Salleh Khiril Shahreza , Bakar Rizal
Published: February 2023

Field A consists of multi stacked reservoirs in high geological complexity and heterogeneity setting, with waterflooding has been the secondary drive mechanism for the past two decades. However, in recent years, the field experiencing significant production decline that warrant immediate mitigation plan and action. Therefore, this paper highlights challenges and best practices in rejuvenating water injected reservoir to improve field production by integrating geological re-interpretation, data acquisition and analytical evaluation.

The reservoir is defined in deltaic environment with complex fluvial reservoir architecture. Despite no indication of structural trap or compartmentalization, there is significant variation in reservoir performance across the field indicates lateral heterogeneity that is affecting the areal sweep efficiency. Poor production-injection allocation data due to commingled production, aggravated by tubing leaks have hindered for an optimum formulation of waterflood strategy in the past. As part of the mitigation plan, depo-facies definition and stratigraphy boundaries were further refined, guided by well and reservoir pressure performance. Besides, inter-well tracer injection implementation proved to be the game changer - unfolded hydrodynamic connectivity and flow path of injected water understanding, established actual producer and injector pairing, and identified poor or unswept areas. It was supported by comprehensive analytical water injection performance analysis including Hall's Plot, Chan's Plot, Jordan's Plot as part of the routine surveillance activities to trigger any non-conformance. More aggressive well intervention also helped to identify and rectify well issues.

As the outcomes, there is opportunity to increase water injection rate by 30% field wide by reactivating idle wells, converting producers to injector, and maximizing the existing injection within the safe fracture limit. The subsurface risks on fracture gradient uncertainty and sweep inefficiency due to water cycling to be mitigated via injectivity test with gradual injection, close monitoring of liquid rate handling at surface, and pattern balancing between injectors and producers. The liquid rate is expected to be restored and sustained nearing the historical peak, hence improve field production and temper the decline.

This paper presents the best practices to address the challenges in a matured waterflood reservoirs, considering the complex geology setting. Understanding of the flood pattern from tracer analysis, supplemented by producer-injection performance assessment and well integrity status validation enabled water injection to be ramped up at the right area in strategically and safely manner.
Generation of Sodium Hypochlorite from Produced Water
Authors: M. Shah M. Faris , M. Timyati M. Fittri , Tengku Mizam Tengku Muhamad Alif Luqman , Azaman Dzulkarnain
Published: February 2023

The major process in crude oil terminal was the separation of light hydrocarbon and water from crude using heat. The daily crude output capacity of a crude oil terminal is in between 90 and 100 kbd. The produced water from the separation unit will flow into the produced water tank before being delivered to the skimmer pits for further treatment. Following treatment, the effluent will be released into the ocean in accordance with the standards set by the Department of the Environment (DOE). Approximately 1,085,681 kl of water with a high concentration of chlorine were discharged by the crude oil terminal per year.

With a high chlorine concentration in place, the large amount of produced water can be used to generate chloralkaline feed. Even if it is now crucial from an environmental standpoint because generated water is regarded as the most significant waste stream, there still needs to be a plan in place for the crude oil terminal to reuse or recycle the wastewater. A baseline analysis was carried out with the present wastewater volume to confirm that water reuse and recycling may provide value, protect the environment, and help the main company to realize its sustainability agenda. Increasing the amount of produced water and wastewater in operations, lowering reliance on outside water supplies, and ensuring the commercial viability of resources are other goals of this study.

In this study, electro-chlorination (ECU), a water filtering process, and a test for free and total chlorine were all used to carry out experiment work utilizing the HACH method. These tests were performed to see out how much chlorine was present in the sodium hypochlorite solution that the ECU generates. The outcome showed that the electro-chlorination process would produce a more alkaline solution the longer it operated. It results from the electrolysis process, which increases the concentration of OH- ions in the solution.

Laboratory testing is done to confirm that the produced water from the crude oil terminal can be used to electrogenerate hydrogen and sodium hypochlorite. The wastewater was subjected to three (3) tests, the first of which involved water filtration to remove suspended particulates, the second of which involved electro-chlorination using an electro-chlorination unit (ECU), which produced NaOCl as a product and H2 as a by-product. Finally, a dilution experiment is conducted to lower the concentration of the NaOCl solution so that it is within the range prior to the Free and Total Chlorine test. Using a Hach DR900 machine, the solution is then tested to determine the amount of free and total chlorine present in the effluent.