bluuebunny/crossref_metadata_2025_split huggingface dataset:
Acid Fracturing Experience In Naturally Fractured – Heavy Oil Reservoir, Bati Raman Field
Authors: Gozel Mustafa Erkin , Uysal Serkan , Ayan Cosan , Yuce Ugur , Ozturk Egemen , Gune Huseyin Kerem , Yilmaz Ismail Sahin , Oymael Mustafa , Eswein Edmund 
Published: September 2021

Abstract
Bati Raman field, with an original oil in place of 1.85 billion barrels, is a naturally fractured carbonate reservoir containing 9-13 °API extra heavy oil with viscosities varying from 300 to 600 cp. Not only a wide range of pilot EOR schemes including gas, thermal and chemical methods, but also novel IOR applications have been tried in the field. CO2 injection was a game changer for this reservoir which has been the main drive mechanism since 1987. Since then, various techniques are applied to further improve the production performance of the field. This study focuses on the design and outcome of the pilot acid fracturing treatments in selected three wells in the tighter and less fractured southeastern part of the reservoir.
State of the art planning included full evaluation of well integrity, cement bond and open hole logs, geomechanics studies augmented with rock mechanics laboratory tests. Laboratory tests were also conducted focusing on sludge/emulsion forming tendencies and acid reaction rates. Using these results, expected fracture dimensions were predicted along with production forecasts. In all wells, pre-frac calibration tests were conducted to assess stress conditions and fracturing parameter optimization. The treatments were then executed, improving the procedure between each well for acid fracturing. Injections schemes were operationally efficient and various diversion techniques were used to mitigate the presence of naturally fractured zones. Pre and post-job temperature logs helped to evaluate each treatment.
The results from the wells were very positive; total production rate increased about fivefold, observed within one month after the treatments. No considerable change in water or CO2 production in the wells was observed which had been one of the most important objectives during the candidate selection process. One well was suspended, which turned out to be one of the producers of the field after acid fracturing treatment. Each well had a different post-frac production performance because of its geological characteristics and flow dynamics, making the study more valuable for better understanding of the process. The wells are still on critical observation to assess the nature of the created fractures and their longevity in the long run. Even after twelve to fifteen months of production, which is the breaking point period for fracture closure, the overall production level of the wells was double compared to pre-frac rates. One well still has a fracture dominated production while other two changed back into its pre-frac rates. Based on these results, acid fracturing campaign was extended in the area which is currently under evaluation.
Does Miscibility Alone Predict the Success of WAG Projects? Key Issues in Miscible HC-WAG Injection
Authors: Alklih Mohamad Yousef , Aljneibi Nidhal Mohamed , Khan Karem Alejandra , Dilsiz Melike 
Published: September 2021

Abstract
Miscible HC-WAG injection is a globally implemented EOR method and seems robust in so many cases. Some of the largest HC-WAG projects are found in major carbonate oil reservoirs in the Middle-East, with miscibility being the first measure to expect the success of a HC-WAG injection. Yet, several miscible injection projects reported disappointing outcomes and challenging implementation that reduces the economic attractiveness of the miscible processes. To date, there are still some arguments on the interpretation of laboratory and field data and predictive modeling.
For a miscible flood, to be an efficient process for a given reservoir, several conditions must be satisfied; given that the incremental oil recovery is largely dependent on reservoir properties and fluid characteristic. Experiences gained from a miscible rich HC-WAG project in Abu Dhabi, implemented since 2006, indicate that an incremental recovery of 10% of the original oil in place can be achieved, compared to water flooding. However, experiences also show that several complexities are being faced, including but not limited to, issues of water injectivity in the mixed wettability nature of the reservoir, achieving miscibility conditions full field, maintaining VRR and corresponding flow behavior, suitability of monitoring strategy, UTC optimization efforts by gas curtailment and most importantly challenges of modeling the miscibility behavior across the reservoir.
A number of mitigation plans and actions are put in place to chase the positive impacts of enhanced oil recovery by HC-WAG injection. If gas injection is controlled for gravity and dissolution along with proper understanding on the limitations of WAG, then miscible flood will lead to excellent results in the field. The low frequency of certain reservoir monitoring activities, hence less available data for assessment and modeling, can severely bound the benefits of HC-WAG and make it more difficult to justify the injection of gas, particularly in those days when domestic gas market arises.
This work aims to discuss the lessons learned from the ongoing development of HC-WAG and attempts to comprehend miscible flood assessment methods.
Experimental Investigation of the Impact of Crude Oil and Rock on Improved Recovery by Low Salinity Water Injection
Authors: Alhammadi Mohamed , Masalmeh Shehadeh Masalmeh , Al-Shehhi Budoor , Sohrabi Mehran , Farzaneh Amir 
Published: September 2021

Abstract
This study aims to compare the roles of rock and crude oil in improving recovery by low salinity water injection (LSWI) and, particularly, to explore the significance of micro-dispersion formation in LSWI performance. Core samples and crude oil were taken from two carbonate reservoirs (A and B) in Abu Dhabi. The oil samples were selected such that one of them would form micro-dispersion when in contact with low salinity brine while the other would not.
A series of coreflood experiments was performed in secondary and tertiary modes under reservoir conditions. First, a core sample from reservoir A was initialized and aged with crude oil from reservoir A and a core sample from reservoir B was initialized and aged with crude oil from reservoir B. The cores were then swapped, and the performance of low salinity injection was tested using rock from reservoir A and crude from reservoir B, and vice versa.
For the first set of experiments, we found that the crude oil sample capable of forming micro-dispersion (we call this oil "positive", from reservoir A) resulted in extra oil recovery in both secondary and tertiary LSWI modes, compared to high salinity flooding. Moreover, in the secondary LSWI mode we observed significant acceleration of oil production, with higher ultimate oil recovery (12.5%) compared to tertiary mode (6.5%). To ensure repeatability, the tertiary experiment was repeated, and the results were reproduced. The core flood test performed using "negative" crude oil that did not form micro-dispersion (from reservoir B) showed no improvement in oil recovery compared to high salinity waterflooding. In the "cross-over" experiments (when cores were swapped), the positive crude oil showed a similar improvement in oil recovery and the negative crude oil showed no improvement in oil recovery even though each of them was used with a core sample from the other reservoir. These results suggest that it is the properties of crude oil rather than the rock that play the greater role in oil recovery. These results suggest that the ability of crude oil to form micro-dispersion when contacted with low salinity water is an important factor in determining whether low salinity injection will lead to extra oil recovery during both secondary and tertiary LSWI. The pH and ionic composition of the core effluent were measured for all experiments and were unaffected by the combination of core and oil used in each experiment.
This work provides new experimental evidence regarding real reservoir rock and oil under reservoir conditions. The novel crossover approach in which crude oil from one reservoir was tested in another reservoir rock was helpful for understanding the relative roles of crude oil and rock in the low salinity water mechanism. Our approach suggests a simple, rapid and low-cost methodology for screening target reservoirs for LSWI.
Simulating Multiphase Flow in Reservoirs with Generative Deep Learning
Authors: Alakeely Abdullah A. , Horne Roland N. 
Published: September 2021

Abstract
This study investigated the ability to produce accurate multiphase flow profiles simulating the response of producing reservoirs, using Generative Deep Learning (GDL) methods. Historical production data from numerical simulators were used to train a GDL model that was then used to predict the output of new wells in unseen locations.
This work describes a procedure in which data analysis techniques are used to gain insight into reservoir flow behavior at a field level based on existing historical data. The procedure includes clustering, dimensionality reduction, correlation, in addition to novel interpretation methodologies that synthesize the results from reservoir simulation output, characterizing flow conditions. The insight was then used to build and train a GDL algorithm that reproduces the multiphase reservoir behavior for unseen operational conditions with high accuracy. The trained algorithm can be used to further generate new predictions of the reservoir response under operational conditions for which we do not have previous examples in the training data set.
We found that the GDL algorithm can be used as a robust multiphase flow simulator. In addition, we showed that the physics of flow can be captured and manipulated in the GDL latent space after training to reproduce different physical effects that did not exist in the original training data set. Applying the methodology to the problem of determining multiphase production rate from new producing wells in undrilled locations showed positive results. The methodology was tested successfully in predicting multiphase production under different scenarios including multiwell channelized and heterogeneous reservoirs. Comparison with other shallow supervised algorithms demonstrated improvements realized by the proposed methodology, compared to existing methods.
The study developed a novel methodology to interpret both data and GDL algorithms, geared towards improving reservoir management. The method was able to predict the performance of new wells in previously undrilled locations without using a reservoir simulator.
Engineers of the Future: Student Training Program for the New Business Model
Authors: Maksyutin Konstantin , Zalevina Anna , Sorokin Pavel , Rukavishnikov Valeriy , Boev Artem , Kharitontseva Polina , Solovev Vasilii , Portniagina Arina , Lukin Alexey 
Published: September 2021

Abstract
A major Russian oil company is currently carrying through an ambitious program aimed at transforming corporate E&P business model. The new model involving product-based approach to exploration and production will require young professionals with new skills and mindsets beyond regular university curricula. To proactively satisfy this demand, the company joined forces with one of its partner universities to champion Engineers of the Future, a training initiative aimed at senior students about to graduate and join the company.
Engineers of the Future offer a fresh perspective and approach to training young professionals, mixing conventional training with problem-based and game-based learning to deliver a unique combination of hard and soft skills required by company's new operating paradigm. Program graduates are expected to make a great addition to corporate product teams, enabling the company to achieve its challenging strategic goals.
A Data-Driven Approach to Predict the Breakdown Pressure of the Tight and Unconventional Formation
Authors: Tariq Zeeshan , Aljawad Murtada Saleh , Murtaza Mobeen , Mahmoud Mohamed , Al-Shehri Dhafer , Abdulraheem Abdulazeez 
Published: September 2021

Abstract
Unconventional reservoirs are characterized by their extremely low permeabilities surrounded by huge in-situ stresses. Hydraulic fracturing is a most commonly used stimulation technique to produce from such reservoirs. Due to high in situ stresses, breakdown pressure of the rock can be too difficult to achieve despite of reaching maximum pumping capacity. In this study, a new model is proposed to predict the breakdown pressures of the rock. An extensive experimental study was carried out on different cylindrical specimens and the hydraulic fracturing stimulation was performed with different fracturing fluids. Stimulation was carried out to record the rock breakdown pressure. Different types of fracturing fluids such as slick water, linear gel, cross-linked gels, guar gum, and heavy oil were tested. The experiments were carried out on different types of rock samples such as shales, sandstone, and tight carbonates. An extensive rock mechanical study was conducted to measure the elastic and failure parameters of the rock samples tested. An artificial neural network was used to correlate the breakdown pressure of the rock as a function of fracturing fluids, experimental conditions, and rock properties. Fracturing fluid properties included injection rate and fluid viscosity. Rock properties included were tensile strength, unconfined compressive strength, Young's Modulus, Poisson's ratio, porosity, permeability, and bulk density. In the process of data training, we analyzed and optimized the parameters of the neural network, including activation function, number of hidden layers, number of neurons in each layer, training times, data set division, and obtained the optimal model suitable for prediction of breakdown pressure. With the optimal setting of the neural network, we were successfully able to predict the breakdown pressure of the unconventional formation with an accuracy of 95%. The proposed method can greatly reduce the prediction cost of rock breakdown pressure before the fracturing operation of new wells and provides an optional method for the evaluation of tight oil reservoirs.
Importance of 3-Way Coupled Modelling for Carbon Dioxide Sequestration in Depleted Reservoir
Authors: Chidambaram Prasanna , Tiwari Pankaj Kumar , Patil Parimal A , Mohd Ali Siti Syareena , M Amin Sharidah , Tewari Raj Deo , Tan Chee Phuat , Widyanita Ana , B A Hamid M Khaidhir 
Published: September 2021

Abstract
Carbon sequestration is the process of capturing and storage of atmospheric carbon dioxide. The objective of any carbon sequestration project is to store CO2 safely for hundreds or thousands of years with a goal of reducing global climate change. A depleted hydrocarbon reservoir is one of the potential storage sites being considered for long-term CO2 storage. The dynamic, geochemical, and geomechanics changes that occur during CO2 injection are inter-related. For example, when injected CO2 causes dissolution of reservoir rock, on one hand, porosity increases while rock strength decreases. On the other hand, reduced rock strength could cause additional compaction thus reducing porosity, whereas increase in pressure due to injection could cause dilation. Hence, it is critical to have an integrated model that captures effect of all changes on the storage capacity and integrity of the reservoir.
Three major depleted gas reservoirs in Central Luconia field, located offshore Sarawak, are being evaluated for future CO2 storage. A 3-way coupled modelling approach that integrates dynamic model, geochemistry model, and geomechanics model is utilized to obtain cumulative effect of all three changes. This integrated model provides a more accurate estimate of 1) CO2 storage capacity, 2) Caprock integrity evaluation, 3) CO2 plume migration path, and 4) Volume of CO2 stored through different storage mechanisms (viz. hydrodynamic trapping, capillary trapping, solubility trapping, and mineral trapping). Apart from providing storage capacity, this model also provides inputs for evaluating integrity of caprock, fault reactivation study, MMV (Measurement, Monitoring, and Verification) planning, and estimating potential leak rates through plugged and abandoned wells.
Using a 3-way coupled model, it is estimated that there is an average reduction in porosity of 5-10% (of initial porosity). This translates to an equivalent reduction in CO2 storage capacity of 5-10% compared to dynamic model. It is observed that pore collapse as a result of pressure depletion is primarily responsible for this reduction in porosity. It has also been observed that the injection can be continued till initial reservoir pressure is reached without breaching caprock integrity. CO2 plume migration path significantly affects MMV planning. Potential leak rate estimation is critical in mitigation and contingency planning.
4D Seismic in Subsurface CO2 Plume Monitoring – Why It Matters?
Authors: Tiwari Pankaj Kumar , Das Debasis Priyadarshan , Patil Parimal Arjun , Chidambaram Prasanna , Chandran Prasanna Kumar , Tewari Raj Deo , Abdul Hamid M Khaidhir 
Published: September 2021

Abstract
CO2 sequestration in depleted carbonate reservoir stipulate incorporation of comprehensive and trailblazing monitoring technologies. 4D time-lapse seismic is sine qua non for Monitoring, Measurement and Verification (MMV) planning to demonstrate the migration of CO2 plume within geological storage. An ingenious, adaptive and site specific MMV plan for monitoring CO2 plume is paramount to minimize possible subsurface and project integrity risks. Integration of dynamic simulation with seismic forward modeling aggrandize the capabilities of 4D seismic in CO2 sequestration projects.
Depleted carbonate reservoir has been thoroughly studied and its geomechanical and geochemical modeling results were coupled into dynamic simulation. Reservoir porosity and fluid properties along with CO2 saturation and injection pressure distribution within each reservoir level were generated. The dynamic simulation results were integrated with seismic forward modeling to demonstrate the CO2 plume migration and its impact on seismic amplitude. Fluid acoustic properties were computed for carbonate reservoir using FLAG method. Selection of wells was based on availability of superior quality acoustic logs as well as those representing the reservoir best. Gassmann fluid substitution exercise was carried using dry rock modeling. Several scenarios were generated, and results were analyzed to demonstrate the effect of CO2 saturation and pressure build-ups within reservoir on the seismic amplitude due to continuous CO2 injection.
Synthetic seismic AVO gathers were generated for angles ranging from 5 to 50 degree. Near, Mid and Far seismic amplitude response at the top of carbonate reservoir were analyzed with respect to in-situ condition for each scenario. Results reveal that CO2 saturation as low as 25 - 30% in depleted carbonate reservoir can be distinguished from 4D time-lapse seismic. With continuous CO2 injection, the reservoir pressure increases and this in turn controls the properties of both in-situ and injected fluids. The gradual changes in fluid properties and their impact on bulk acoustic properties of reservoir were modeled to assess the feasibility of using 4D seismic as a predictive tool for detection of localized and provincial pressure build-ups. Modeling results show that although observed changes in amplitude on synthetic gathers were subtle, it is expected that 4D seismic with high signal-to-noise ratio possibly be able to image such localized pressure build-ups. To monitor CO2 plume migration as well as localized pressure build-ups, we recommend acquiring multi-azimuth (MAZ) surface seismic in combination with 3D DAS-VSP for superior subsurface imaging. The integrated modeling approach ensures that 4D Seismic in subsurface CO2 plume monitoring is robust. Monitoring pressure build-ups from MAZ surface seismic and 3D DAS-VSP will reduce the associated risks.
Deployment of Downhole Hydraulic Lubricator Valve Enables Safe and Efficient Perforating and Production Testing Strategy – Case Study in Jambaran High Rate Gas Field, Indonesia
Authors: Rena Rahmawan , Robb Ewan , Maulana Ibnu , Batubara Aswin , Yulia Yulia , Wagianto Wagianto 
Published: September 2021

Abstract
This paper details the first implementation of a deep-set downhole hydraulic lubricator valve (DHLV) in Indonesia. This application was implemented in Jambaran field, onshore Central Java as part of Jambaran-Tiung Biru (JTB) national strategic project. Jambaran is a large carbonate gas field development located in proximity to densely populated areas. Since the field's reservoir contains significant concentrations of CO2 and H2S, it was important to design the completions to be able to perforate and test the wells safely without endangering the surrounding area.
To produce as per reservoir management strategy, 800 ft of reservoir section drainage was required. Multiple completion designs were considered in the initial stages which included consideration of an open hole completions design, multiple wireline perforating runs and a cased hole live well single trip coiled tubing gun system. The rigless single trip coiled tubing gun deployment system was chosen due to safety and efficiency factors. With a deep set DHLV as the primary barrier in controlling the wells following perforating substantial daily rental cost savings can be realized during perforating operations.
JTB field was developed by drilling 5 new well plus 1 re-entry well. The completions design was similar in all 6 wells. A 2 step completion design was utilized, to compensate for life of well tubing movement load, this consisted of a polished bore receptacle and production packer assembly in the lower completion. The 2nd stage of the completion consisted of 7" × 5-1/2" tubing with Tubing Retrievable Safety Valve (TRSV), DHLV, Permanent Downhole Gauge (PDHG) and production seal assembly. Strategically placing the PDHG below the DHLV enabled monitoring of bottom hole pressure during shut in without use of memory gauges validating the DHLV as primary barrier during gun retrieval. The production seal assembly was tied back into the lower polished bore receptacle that was previously set.
The deep-set DHLV enabled the operator to (i) safely run long TCP gun assemblies up to 911 ft of gross gun length per well to perforate the whole well in 1 trip, (ii) POOH guns efficiently with one time bleed off (iii) efficiently initiate the pressure build up phase by shutting in the well against the DHLV as opposed to a surface valve prior to flowing the well and (iv) gun assemblies retrieved without the need to kill the well.
After completing and well testing all 6 wells, the benefits of implementing the deep-set DHLV was immediately realized. By perforating underbalanced, omitting the well kill process and immediately proceeding with pressure build up by closing the DHLV resulted in operator savings of approximately 1.5 million USD over the entire rigless completion campaign.