bluuebunny/crossref_metadata_2025 huggingface dataset:
An Acoustic-Based Method for Measuring Surfactant Concentration in Field Applications
Authors: Al-Sadeg Hala , Felix Servin Jesus Manuel , Abdel-Fattah Amr I.
Published: November 2020

Numerous enhanced oil recovery (EOR) techniques entail injecting chemical treatments such as surfactants at a predetermined concentration to achieve targeted results. Typically, these formulations are prepared on-site prior to injection into the reservoir using large mixing tanks. The current quality assurance practice for proper concentration of treatment materials uses indirect methods such as interfacial tension (IFT) and/or viscosity measurements. These measurements can be lengthy or only suitable for a specific range of dispersed phase volumes.

We examined the prospect of using acoustic measurements as a method to determine surfactant concentration for quality assessment of chemical injections on-site. The advantage of ultrasound is that it can characterize both concentrated systems and low dispersed phase volumes. In this study, we acquired the sound attenuation of an amphoteric surfactant, Cocamidopropyl Hydroxysultaine (CBS), and in-house petroleum sulfonate surfactant nano-capsules (NanoSurfactant), within a frequency range of 3-99.5 MHz. We conducted a set of experiments to establish the relationship between acoustic attenuation and surfactant concentration, and assess the measurements’ dependence on variable factors including applied frequency, suspending fluid, and temperature.

The data showed a nearly perfect linear fit in the higher frequency range (65-99.5 MHz) where the coefficient of determination was between 0.979-0.998. Consistent with theoretical predictions, this method showed sensitivity to water salinity where the surfactant, at a constant concentration, displayed higher attenuation values in response to the increase in water salinity, allowing the contribution of surfactants to the acoustic attenuation to be isolated. Our method accurately determined surfactant concentrations using acoustic attenuation regardless of the surfactant used.

Adopting such a robust protocol that can determine surfactant concentration and has the potential to improve field quality assurance methods would be beneficial for EOR research and industry applications whether as a standalone system or in conjunction with other commonly available methods.
Integrated Analytical Workflows for EOR Surveillance, Management & Optimization
Authors: Nazri Syakirin M , Sidek Sulaiman Sidek , Tan Tan Kok , Tang Catherine Tang , Hamzah Haziqah Bt , Bakon Freddy Layang , Haron M Fakhrullah , Chee Louis Chee , Sharim Noor Azima , Yunos Khairil Anuar , Nghia Vo Tri
Published: November 2020

Field W is a matured field offshore Sarawak with multiple reservoirs undergoing oil rim management and Immiscible Water Alternate Gas (IWAG) scheme, in addition to rejuvenation of various facilities used for power generation, living quarters, gas export/injection, water injection and oil/gas production. As such, new ways of working are required to ensure the successful of Enhanced Oil Recovery (EOR) redevelopment.

The holistic workflows obtain optimum amount of real-time data information for details calculation, monitoring and analysis in form of maps, charts and tables to allow evaluation, derisking and mitigation of deviation from EOR plans. These integrated solutions consist of two main work groups, 1) EOR Surveillance and 2) EOR Management and Optimization. EOR Surveillance group designed to monitor performance of the production and injection systems (from reservoirs, wells to facilities), to detect deviations from planned targets/performances using simple diagnostic tools and to provide functionalities for EOR and RMP compliance tracking. EOR Management and Optimization group provide advanced analytical tools to diagnose overall EOR performance in each reservoir (pressure, sweep and displacement efficiencies), improve predictive ability of reservoir simulation models and diagnose abnormalities in the context of actual measurements versus long-term production forecast.

Consequence from integration of all information in one medium, the solution helps to; 1) Increase the production and recovery factor through prudent monitoring and total asset optimization. 2) Intelligent alarms and alerts to reduce the unplanned deferment and downtime for continuous asset awareness.3)Increase the operational efficiency through streamlined and automated workflow processes, allows faster informed decisions by highlighting possible related measurable or calculable KPIs as key information for issue analysis from one source supported with required visualization.4) Validated data acquisition and dissemination across the organization to create a collaborative work environment among multiple disciplines and locations, where opportunities for improvement can be analyzed and corrective actions can be undertaken. 5) Remote monitoring of the offshore facilities from the Regional and Central Head Quarter which are thousands of kilometers apart.

This paper aims to showcase the automation of routine workflow by development and deployment of integrated real-time data driven technical workflows, a PETRONAS standard solution for EOR surveillance, management and optimization based on relevant data acquired from appropriate field instrumentations, complemented with defined analytical workflows and advanced collaborative environment.
Experimental Study on the Methane Hydrate Formation in Water-In-Oil Emulsions with Dissolved Wax
Authors: Tong Shikun , Wang Zhiyuan , Xie Kai , Liu Jian , Zhang Jianbo , Fu Weiqi , Sun Baojiang
Published: November 2020

The investigation of the hydrate formation in water-in-oil emulsions with dissolved wax is significant to mitigate hydrate risk with the development of deep water gas filed. Experiments are designed by using high-pressure stirred reactor to simulate hydrate formation under high pressure and low temperature. The characteristics of nucleation time, formation rate decomposition characteristic and hydrate strength under different wax concentrations is studied with the variation of temperature and pressure. Hydrate formation have four stages include initial gas dissolution, then induced nucleation, last mass formation and final anneal time. The mass transfer resistance of hydrate increase as the wax increase at low concentration, which increase the hydrate nucleation time and decrease the gas consumption of hydrate. However, the hydrate nucleation and formation with abundant wax crystals is different than low concentration due to the fragmentation of droplets by wax crystals, which increase the contact area of gas and liquid. Moreover, wax crystal increase the heat transfer resistance during the process of hydrate decomposition, prolong the decomposition time of hydrate, and increase the difficulty of hydrate blockage removal. In addition, hydrate particles alter the adsorption force between hydrate particles and decrease the strength with the wax concentration increase. The work illustrate the characteristic of hydrate formation with dissolved wax, which is significant to design and optimize the hydrate management strategies in the deep water gas field with dissolved wax.
Performance Comparison of Retarded Acid with Emulsified and HCl/Formic Acid Recipes for Carbonate Acidizing
Authors: Al Moajil Abdullah , Aljuryyed Norah , Alghamdi Saeed , Caliskan Sinan
Published: November 2020

Various acids and chemicals have been developed to achieve retardation properties to enhance oil and gas production. Improving acid retardation through emulsification or polymer gelling agents has drawbacks. Retarded acid recipes including HCl, organic acids, and/or chemical retarders showed comparable retardation efficiency. This paper aims to compare the performance of non-viscous retarded acids and benchmark them against emulsified acids (Hall-Thompson et al. 2020).

The proposed acid recipes are either a combination of HCl, formic acid with or without inorganic/organic retarders. Emulsified HCl acids at 15 wt% were prepared as a retardation baseline. Carbonate dissolution was assessed using solubility testing with calcite discs. Coreflood testing was conducted using Indiana limestone core plugs to assess the pore volume profile at temperatures up to 300 °F. This study was supported by Computed Tomography, to evaluate the propagation behavior as a result of the fluid/rock reaction.

The solubility calcite discs in the retarded acid recipes showed acid retardation comparable to emulsified acid. The surface tension values of retarded acid recipe were between 19.5-38.5 dynes/cm at 70-300°F. The coreflood results showed retardation performance comparable to emulsified acids at 200 and 300°F. The retarded recipes were capable to prevent nearly 1,500 mg Fe/L from precipitation in spent acid. The corrosion loss and pitting indices were within <0.02-0.09 lb/ft2 using retarded acid recipes at 170-300°F (i.e., <0.02-0.09). The optimum injection rates of retarded acid recipes were nearly 1 and 2 cm3/min at 200 and 300°F, respectively. The results obtained with HCl/Formic acid recipes showed generally competitive retardation performance compared to retarded acid recipes with limitations discussed in the paper.
New Novel Constitutive Model for Solid Production Prediction with Laboratory Test Validation
Authors: Subbiah Surej Kumar , Mohamad-Hussein Assef , Samsuri Ariffin , Jaafar Mohd Zaidi , Chen Yingru , Pearce Andrew , Paramanathan Rajendra Nath
Published: November 2020

Sand production can cause serious chaos at the wellhead and needs a proper geomechanical analysis to understand the failure and post failure mechanisms. Thus, a proper constitutive model (failure criteria) is required for this effort as most of the available failure criteria are not specially developed for sandstone. The post failure (Softening) part is not normally captured in many of the existing models. For this reason, a new elastoplastic constitutive model for sandstone has been investigated and developed. A serious attempt was made to capture both the hardening and softening of the sandstone rock. The effort started in the laboratory with a series of triaxial tests conducted for different confining pressure for 3 types of sandstone. A systematic approach has been used to analyses the rock mechanical data to pick proper yield, peak and residue strength, besides common elastic properties. A new constitutive model is then developed and validated. The new constitutive model (known as Assef-Surej-Ariffin, ASA model) is able to capture the full elasto-plastic rock mechanical behavior including softening and post failure which is critical for oil and gas applications such as sand production and drilling. An FEM code is used to validate the new constitutive model and the results compared with the modified Mohr Coulomb criteria. The results show that the new ASA constitutive model gives a better match for most of the laboratory tests compared to Mohr Coulomb especially for the softening part. The new ASA failure criteria is planned to be used in sand production analysis to estimate the sanding propensity and rates where the post failure analysis will be key to the results.
Optimization of Microsphere Injection by Balancing the Blocking and Migration Capacities in a Heterogeneous Carbonate Matrix
Authors: Cao Dongqing , Han Ming , Wang Jinxun , AlSofi Abdulkareem
Published: November 2020

Microsphere injection aiming at in-depth fluid diversion is based on the microsphere retention induced by the particle-rock/brine interaction in hydrodynamic environment. The retention generates steric blocking to the high permeability zones but retards the microsphere migration to the deep reservoir. This work studied the flow properties of microsphere samples in heterogeneous carbonate core plugs for an optimum blocking and migration capabilities. The oil production potentials of blocking-dominant and migrate-dominant microsphere samples were compared.

Coreflooding tests were performed to evaluate the microsphere flow properties and oil production potential at 95°C and 3100 psi pore pressure. The carbonate core plugs with middle to high permeability were used. The flow property evaluation started with quantitative microsphere injection of eight pore volumes, followed by postwater injection. The injection pressures were recorded and produced microsphere concentrations were monitored. Oil displacement tests were conducted using selected microsphere candidates by 1 pore volume microsphere injection after waterflooding. Effects of microsphere sizes were investigated.

The flow properties of eight microsphere samples with different particle sizes and aggregation properties were evaluated. Particle size was a dominant factor for the microsphere flow in the core plugs. Larger particles tended to retain in the pores rather than migrate forward, resulting in higher flow resistance with less breakthrough. Suspension in polymer solution improved the ability to penetrate deep into the formation. Microsphere with better coalescence stability in the brine showed better migration performance. Three microsphere samples with particle size at nano-, sub-micron and micron scale were selected to evaluate the oil production potential. One pore volume microsphere injection by the nano- and sub-micron microspheres after waterflooding increased oil production by 11% and 16%, respectively, which were much higher than the oil production by micron microsphere injection. A balance between effective blocking and deep migration was required to achieve optimal performance. The optimization process is developed for the microsphere injection in the field application.
Core-Independent Saturation Height Function from NMR Logs in Carbonates-A Must in Current Oil Price Environment
Authors: Nandi Anindya , Mondal Ilius , Jain Vikas , Vij Jitesh , Verma Ankit , Chaturvedi P. C. , Haldia B. S.
Published: November 2020

The present oil industry is more challenged than ever to develop novel methods for oil exploration and production, while reducing costs at the same time. This necessity changes the need of logging tools for reservoir characterization. Saturation height modeling (SHM) is an important aspect of determining the production capability of an oilfield. This is often performed by taking core samples, which is pivotal for such analysis, but expensive and challenging. Further, cores are usually taken in the zones of interests in the well. This calls for an alternate analysis, which is not only available for the entire interval of the well but is also less expensive than the traditional coring techniques.

Nuclear Magnetic Resonance (NMR) applications have proved promising over the years to perform SHM, without using cores. NMR, however, has a shallow depth of investigation and using wireline measurements is even more challenging due to longer time after bit and increased mud filtrate invasion. Consequently, its use is restricted to quantifying porosity. This makes it imperative to remove the effect of any filtrate or hydrocarbons from NMR logs to be able to use them for any advance analysis.

A novel methodology is presented in this paper to perform SHM analysis in carbonates. It uses NMR data along with modern processing techniques like factor analysis (Jain et al. 2013) and fluid substitution (Minh et al. 2016) and integrated workflow to define hydrocarbon uncontaminated pseudo capillary pressure curves and saturation height functions for different rock facies observed in the formation. The results are validated on five wells in the same field, and further confirmation is also done with testing results.
Kahmah Reservoir Conceptual Model in South Sultanate of Oman: A Case Study of Field Extension
Authors: Sabahi Atiya , Rahbi Said , Harthi Mahmood , Choudhury Suryyendu , Darmaki Faisal , Lawati Ali , Ghatrifi Suhaib , Mahrouqi Iman , Morianta Marpaung , Abri Yaqoob , Al-Jumah Ali
Published: November 2020

The objective of this study is to evaluate and de-risk the extension of the Kahmah Group, which is a newly identified carbonate extension in the Eastern part of XX field, and to assess and unlock further appraisal and development opportunities.

Eastern field correlation was done by correlating the wells that has encountered Kahmah carbonate, the ones showing low Gamma Ray (GR) traces. Well correlation was done mainly on Petrophysical properties of three vertical penetrations that show distinct and abrupt change from high GR (Base Nahr Umr Shale and/or Mahwis sandstones) to low GR reflecting Kahmah carbonates.

Based on the thicknesses of Kahmah based on the vertical well data and commercial oil seen in all wells in the vicinity, thickness and expected oil distribution maps were created.

The main findings from the correlation are: 1) Kahmah reservoir is divided into two pays and two non-pays zones as seen in XX-1H1. 2) The reservoir is thickest around XX-1 and thins out toward YY-10 to the south and disappears completely in XX-5 to the north, portraying a wedge- shape.

Kahmah reservoir varies in thickness, with thickest interval encountered in XX-1 with 11m. The reservoir thins out towards the edge closer to YY-10 confirming the wedge-like structure.

A conceptual understanding has been incorporated in generating cross-sections portraying and proving the wedge-shape structure of Kahmah.

Like any other new formation development, many uncertainties are associated with Kahmah development like formation extension, reservoir/fluid properties, pressure behaviour and others.

The key observations from this project can be summarized as following: Different packages of reservoir. May be of different or similar propertiesExtension of Kahmah towards northern part of XX field is still highly uncertainContinuity of Kahmah Reservoir is uncertainReservoir pressure and communication with Mahwis formation need to be evaluatedReservoir and fluid properties also need to be evaluated
Fracturing and Production Observations from the First Two Horizontal Wells for Shale Oil Exploration in Ordos Basin
Authors: Hou Yuting , Wu Yong , Hu Xifeng , Tang Meirong , Liu Yuan , Zhang Jie , Niu Li , Xu Wenran
Published: November 2020

The continental depositional environment poses unique challenges for the exploration of unconventional resources. The tight reservoir nature requires horizontal drilling and multistage completion. However, the geologic discontinuity and the geomechanical heterogeneity complicate lateral completion design, fracturing treatment execution, and production analysis. The experience of developing the first two horizontal wells for shale oil exploration in the Ordos basin resulted in observations that link the geology, reservoir, geomechanics, and production behaviors, which can be used for future appraisal and development in similar environments.

In 2014, one exploration well in the south Ordos basin demonstrated that the source rock from the Chang-7-3 formation could produce good light oil, but the tight reservoir needed horizontal drilling and multistage fracturing completion to achieve the production potential. In 2019, two horizontal wells were placed adjacent to each other for appraisal purposes. Due to the unique lacustrine deposition environment of the Chang-7-3 formation, landing the laterals in the target formation proved to be very challenging even with special geosteering tools. For both wells, the net-to-gross ratio is less than expected (51% and 38%), creating significant challenges for the ensuing completion phase. The multistage completion and fracturing were designed with full consideration of the horizontal lateral conditions. Reservoir quality (RQ), completion quality (CQ), and geology quality (GQ) were considered to optimize the completion staging strategy and fracturing plans. Besides the pressure response during fracturing, two additional monitoring and evaluation systems were deployed during the completion phase: microseismic interpretation and chemical tracers. Observations from these three measurements provided valuable information of how the formation responded to the staging strategy, fracturing initiation and diversion, and flowback and production.

Post-fracturing production from both wells met expectations in the testing phase. Additionally, the observations during fracturing and flowback of those two wells provide unique value for better understanding the Chang-7-3 formation. Fracture initiation proved to be feasible only in the lateral sections with proper sand facies where good RQ and CQ were found. Microseismic monitoring showed fracture orientation and planar extension in space. Tracer results revealed where the formation hydrocarbons came from and how the two wells interacted. This case study will have significant influence for future drilling and completion in the Chang-7-3 formation and provide a useful case history for continental shale oil scenarios.
Collapse Design of UOE-Pipe Wellbore Casing
Authors: Liu Zhengchun , Samuel Robello , Gonzales Adolfo , Kang Yongfeng
Published: November 2020

Recently, well design engineers attempted to replace traditional API 5CT pipes with cheaper UOE steel pipes in the downhole wellbore construction. The UOE method for producing longitudinally welded large-diameter pipes creates typically weaker pipes in terms of collapse resistance. The standard API 5C3 collapse design procedure no longer meets safety requirements. A practical solution to this issue is discussed.

UOE pipe casing can be designed based on the new collapse strength envelope, which is established by modifying the API RP1111 collapse strength model. The original API RP1111 collapse strength model was intended for pipeline design, not downhole tubular design. It is comprised of the elastic collapse term and yield collapse term, with the latter being proportional to material yield strength. However, the deration effects of temperature, tension, and internal pressure are not included. For downhole wellbore tubular design, yield strength is replaced with equivalent yield strength (from API 5C3 new addendum), which is a function of temperature, axial stress, and internal pressure.

A new casing design workflow has been implemented in the computer program, and case studies were performed to verify the collapse design results. A new collapse pressure envelope was generated using the computer program integrated with a commercial tubular design tool and was compared to the traditional API 5C3 collapse pressure envelope. As expected, the new collapse strength values, calculated using the modified API RP1111 collapse model, are typically much lower than the estimated values using the API 5C3 collapse formula.

Results of the collapse safety factor and maximum allowable wear are also compared between the modified API RP1111 collapse model and the traditional API 5C3 collapse model. Typically, UOE pipe using the modified API RP1111 collapse model generates lower safety factor and maximum allowable wear values, as expected.

The API RP1111 collapse strength model has been modified to include the deration effects of downhole conditions. Implementing this model in the commercial tubular design tool enables the cost-effective design of wellbore casing strings using cheaper UOE-manufactured steel pipes.
A Novel Characterization and Evaluation Method of Flow Field and its Application
Authors: Qiao Yan , Yang Xiangtong , Zhang Yang , Wang Yonghong , Hou Tengfei , Huang Bo , Shang Litao , Li Huili
Published: November 2020

At present, most of the oil fields in eastern China have entered the stage of high water cut development, with a comprehensive water cut of over 90% and an oil recovery of less than 30%. To improve oil recovery, the flow field must be described qualitatively and quantitatively, so as to provide a basis for the formulation of measures. This paper proposes two categories of indicators: one is a guideline for developing measures, including streamline bundle properties, and the other is an indicator for evaluating the effects of measures, remaining oil dispersion (ROD) and dynamic heterogeneity included. Through numerical simulation methods, the regularity research and adaptive evaluation of each flow field characterization indicator are carried out. Finally, according to the streamline bundle properties of block E, the liquid rate of injection and production wells were optimized, and the effectiveness of the optimization was evaluated. The study found that under the condition of fixed well pattern, the streamline bundle flow (SF) between wells is relatively stable, and the change in streamline bundle potential (SP) and streamline bundle oil cut (SOC) tends to decrease with time. The typical curve of ROD generally includes four stages, and the effectiveness of measures is judged by the trend of ROD. For dynamic heterogeneity, the change curve generally includes unstable stage and stable stage. The value of the stable stage value can reflect the heterogeneity of the flow field. The larger the value, the stronger the heterogeneity of the flow field. According to the streamline bundle properties, three liquid rate optimization strategies, which are streamline bundle flow method (SFM), streamline bundle potential method (SPM), and streamline bundle oil cut method (SOM), are proposed, and the effectiveness of the measures is evaluated using ROD and dynamic heterogeneity. After liquid rate optimization, the ROD of the reservoir in Block E increased and decreased later, the Lorentz coefficient decreased, and the recovery increased by 3.76 percentage points. It provides a new technical means for the adjustment and evaluation of the flow field in the later stage of high water cut oilfield development.
Integrated Reservoir Characterization and Completions Design Using Petrophysical and Acoustics Logs in Unconventional Tight Formation
Authors: Das Ritwika , Chatterjee Chandreyi , Jain Vikas , Majumdar Chandan , Hussain Syed Aaquib
Published: November 2020

With all the conventional reservoirs being almost exhausted around the world, our immense dependency on unconventional reservoirs has led us to look for measurements that are beyond conventional way. In the optimal exploitation of unconventional reservoirs, integrated Petrophysical and Geomechanical studies provide the best means to both 1) evaluate formation properties such as fluid types, volumes and flow potential, and 2) use this information along with rock's mechanical properties to optimize completions program and maximize production. While a basic petrophysical study can be made using triple combo logs gamma ray, neutron porosity, density and resistivity - for reconnaissance and quick look, such studies are not enough for the purpose of completions and production optimization in unconventional. A combined study using different petrophysical, geological and acoustic logs is used in order to answer the questions and problems faced during characterizing a tight unconventional reservoir. The answer products from these will help in advanced studies which would include reservoir characterization and completion design.

For that, we would need to bring in acoustic measurements to determine rock types and respective mechanical properties, which would be influenced by fracture, anisotropy, stress direction and permeability of the formation. Spectroscopy logs will further add to knowledge of the lithology at mineral level, required for petrophysical evaluation and rock physics modeling. Today advanced spectroscopy logs also measure Total Organic Carbon (TOC) percentage of the formation, important to understand source rock maturity and to determine true flow potential in tight formations. Images from Micro Imaging resistivity tool are important in unconventional to evaluate fractures which often times are the only source of permeability in tight rocks. Nuclear Magnetic Resonance is considered essential to determine fluid types, respective volumes and bulk permeability of unconventional formations. An integrated study using all the above measurements helps best combine Petrophysical and Geomechanical aspects of the formation under investigation. Furthermore, in unconventional reservoir evaluation, such a study helps us to determine stress barriers to hydraulic fracturing important to zone-wise design and optimize completions program.

In this paper, we present a systematic procedure and corresponding results of an Integrated Petrophysics and Geomechanics study in an unconventional tight reservoir, which helped to 1) optimize hydraulic fracturing and completions program, and 2) create complete model of hydrocarbon production.
Methodology and Approach of Lightweight Cement Evaluation in Horizontal Well for Integrity Assurance and Future Reservoir Development
Authors: Jongnarungsin Sarunya , Nimchinda Paritas
Published: November 2020

Well integrity is a critical issue for oil and gas companies. The failure of a wellbore integrity can result in financial consequences, have environmental impacts, and could damage a company's reputation. Cement placement is one of the most critical components with respect to ensuring mechanical support of the casing, protection from corrosion and isolation of permeable zones. Light weight cement recipes can help to overcome lost circulation problems during drilling or cementing, however, there are challenges with respect to the applications of Cement Evaluation logs, which are used to determine the effectiveness of the cement job. This is due to the fact that light weight cement exhibits high amplitude and little alteration in the log waveform on conventional bond logs because of its lower fluid density and compressive strength.

This research describes the application of an Advanced Ultrasonic Imaging Tool that combines traditional pulse-echo techniques with a new ultrasonic technique, which can differentiate low-density solids from liquids and distinguish light weight cements from contaminated cement or liquids. Furthermore, this research describes the application of the tool in a highly deviated well, which required the usage of a tractor deployed wireline operation. The results indicated low decentralization readings across the logging intervals and reflected the good data quality observed in the ultrasonic measurements. The processing flag track did not identify the presence of any errors related to the echo acquisition and data processing throughout the logged interval. Overall, a strong signal reflection was observed along the logging interval, suggesting clean inner casing surface. The combination of light weight cement logging on a tractor conveyance tools has been proven to be a successful approach. The application of this technique benefits Mubadala Petroleum Thailand with significant cost savings and reduced Health, Safety and Environment (HSE) risks for the overall operation.

This paper will demonstrate the following:

Cement bond log and evaluation of light weight cement by Advanced Ultrasonic Imaging Tool in comparison to conventional cement bond log tool Job design, efficiency gains and improved well integrity assurance from the operation Special cement designs intended to reduce the weight while maintaining important physical properties, i.e. compressive strength. Efficient downhole data acquisition methods utilizing wireline tractor logging

The material presented in the paper is based on the actual operations of Mubadala Petroleum, with examples illuminating light weight cement used in a horizontal well, as well as the combined application of an isolation tool with a wireline tractor, which is the first such application in the Gulf of Thailand. It will also show the well integrity assurance achieved, operational efficiencies gains and risk reduction obtained.
Critical Success Factors for EPRS Planning and Management
Authors: Cavallini Francesco , Quick Anthony
Published: November 2020

In the current market distress, characterized by reduced oil price and uncertain future, the focus on subsea integrity management is becoming crucial. Operators are often seeking comprehensive Life of Field services, over-taking the former conventional, planned and reactive Inspection, Maintenance and Repair strategy.

In this historical phase, maximization of uptime and extension of producing field operational life are deemed paramount, and such focus on asset integrity is even more crucial for aging subsea assets. Likewise, when a new development is sanctioned, many resources are invested to ensure efficiency and long-term productivity in a sustainable manner. This is particularly true subsea, where technological implications have a greater impact and where risk exposure can be high due to ship traffic, fishing or the like. Inevitably, these developments require constant attention to ensure a satisfactory productivity is maintained, and this is typically achieved by planning and executing IMR campaigns. However, experience has shown that regular inspections may not be enough due to the threats posed by external interfaces (vessels, anchors, fishing gears…), unexpected environmental influence (extreme conditions, earthquake, seabed motions, etc.) or even sabotage, which may be more demanding than the usual conditions a subsea pipeline is designed for, e.g. operational loads, corrosion, vibrations, fatigue, etc. Consequences may be either reduced production or a complete shutdown, which in some cases may be associated with extreme, temporary, containment measures.

These risks require to be identified and addressed by developing an Emergency Pipeline Repair (EPR) strategy grounded on reliable/field-proven solutions and specialized capabilities, which privileges the safest diverless approach over traditional diving solutions, especially when dealing with unknown pipeline conditions. In all regions, such EPR strategy shall address the Critical Success Factors presented in this paper, i.e. Engineering, Technology, Intervention capabilities and Preparedness, which are the cornerstones where to develop a proactive approach towards emergency situations in the frame of a comprehensive Life of Field philosophy. This paper also provides an overview of repair solutions adopted in various regions around the World, with an insight into the technological challenges to be faced for repairs in the Arabian Gulf present and future developments.
Underbalanced Well Intervention to Re-Enter a Dead Well Changed the Future Dynamics of the Largest Gas Field in Pakistan – A Successful Pilot Project
Authors: Ashraf Qasim , Khalid Ali , Luqman Khurram , Hadj-Moussa Ayoub , Hamim Nasir
Published: November 2020

The world was feared to hit peak oil early in the 21st century but oil demand continued to grow and most oil and gas companies dedicated a large budget into developing advanced techniques to maximize production from existing maturing fields while minimizing costs in future exploration. Some of these techniques focused on managing the reservoir heterogeneities, enhancing the production lift mechanisms and reducing reservoir damage while drilling. The end goal however was always to increase the ultimate recovery of hydrocarbons from proven reserves.

Pakistan an energy deficient country and a net importer of oil and gas is in dire need of self sustainability in oil and gas. Located in southern Pakistan, Qadirpur field once produced upto 600 MMSCFD of gas, currently produces only 250 MMSCFD of gas. The primary reservoir in the field is a water drive reservoir which after extensive pressure depletion has caused water conning and fingering in a large number of wells. Recent attempts to drill new wells have suffered massive lost circulation resulting in severe reservoir invasion damage, and ultimately zero production was observed in a most recently drilled well.

As a final resort the operator opted to perform a well intervention in an old and dead well with underbalanced drilling techniques to drill a horizontal leg in the narrow pay zone of the reservoir. The underbalanced drilling campaign was expected to eliminate lost circulation and the ensuing invasion damage to the reservoir formation, characterize the reservoir while drilling and identify sweet spots, and finally increase efficiency of the drilling process and reduce the associated costs.

For the pilot well, a multiphase underbalanced drilling fluid was designed to achive extremely low bottom hole pressures, then appropriate directional drilling equipment with electromagnetic measurement while drilling tools were selected to operate with multiphase fluids, and finally a downhole isolation valve was incorporated in the last casing string to allow tripping without the need of ever killing the well.

The execution of underbalanced drilling in the pilot well resulted in an unprecedented gas production rate of 14 MMSCFD, identified a sweet spot of hardly 0.5 meters in true vertical depth (TVD) of the pay zone, and increased drilling performance upto 3 times of a conventionally drilled well. The success of the pilot well changed the dynamics of the depleting Qadirpur field as a well intervention on an old and dead well could yield the same production as on a new well while costing half as much. The paper elaborates on the techniques applied and lessons learnt on the pilot well.
Protect Wells During Frac Plug Drillouts and Well Flowback Operations for Hydraulically Fractured Wells – The State of The Art in 2020
Authors: Potapenko Dmitriy , Theuveny Bertrand , Williams Ryan , Moncada Katharine , Campos Mario , Spesivtsev Pavel , Willberg Dean
Published: November 2020

Highly efficient multi-stage hydraulic fractured horizontal wellbores are the dominant completion method for many basins worldwide. This completion workflow is followed with the well start up operations, usually consisting of the frac-plug drill out (FPDO) and the well flowback, designed for preparing the well to the production period. Poor management of FDPO and flowback operations on wells with freshly constructed hydraulic fractures, may jeopardize the investments made in completing the well, and may seriously reduce the well’s profitability. Previously reported results show that flowback and initial production practices have a major impact on proppant production, maintenance and disposal costs, and the subsequent well performance. In this paper we present the summary of the results obtained from the analysis of over 200 FPDO and flowback operations in the United States and Argentina. These results show that operating a well within the safe stability limits of the hydraulic fracture network minimizes risk of fracture damage and maximizes well performance.

Earlier it was shown that typical plug drillout operations consists of a series of underbalance, overbalance and balance periods. Multiple rapid transitions between these conditions and performing plug drillout operations outside of the fracture stability limit, was shown to destabilize the proppant pack and mobilize proppant from the fractures. In this paper we evaluate the impact of the various plug drillout strategies on the proppant distribution in the fracture, and draw conclusions about the strategies that help to preserve fracture conductivity. We also demonstrate that using high-frequency monitoring of the surface rates is key for managing plug drillout operations to minimize mobilization of the proppant from hydraulic fractures.

Use of the recently introduced Secure Operating Envelope (SOE) concept was found to be very beneficial for managing well flowback and the production operations. In this paper we demonstrate how the use of the SOE methodology was used for identification of the root cause of the proppant flowback and deriving the appropriate choke management strategy for solving this problem.

At the end we conclude that majority of the highlighted problems can be solved through optimizing the well start up operations as a part of the entire well construction process with making changes to the well construction workflow. Implementing certain changes to fracture treatment design should enable maximization of the well production performance and optimize the well economics.
Geologically Consistent History Matching Honouring Rock Types Driven by Adjoint Method
Authors: Jenei Bettina , Ganzer Leonhard , Almuallim Hussein , Manasipov Roman
Published: November 2020

Most history matching (HM) tools consider only the minimum and maximum geological constraints during their calculations. As a result, after several iterations, the link between petrophysics and SCAL data is often lost. The iteratively created model suffers from certain geological inconsistency, as for example porosity/permeability relations are not honouring their petrophysical constraints. In this paper the relation between model parameters is coupled to rock types which are iteratively updated as a part of the history match process.

An adjoint history match method is used to predict permeability updates for all individual grid blocks. Whenever the permeability (or other property) value of a grid block falls outside the typical range or violates the geological consistency limits, the rock type of the related grid block is moved to a better fitting class. This approach coupled with the adjoint method will provide an improved history match workflow. The workflow is presented for synthetic simulation models and the results are compared against benchmarks.

The modification of rock types driven by areal permeability improves the HM workflow. The rock types have different permeability ranges, relative permeability curves with different connate water and residual oil saturations. Based on the areal permeability, the rock type is changed with corresponding parameters at grid block level. The extended workflow of HM allows parameters to be modified co-dependently according to the rock type definition, after the permeability adjustment suggested by adjoint based algorithm. The results show obvious improvements in HM quality in terms of geological consistency with less iterations. This workflow is an efficient extension for HM of oil and gas fields. Potential challenges can arise in this approach. The rock type distribution may change compared to the initial setting. Since the initial volume calculation is based on rock type dependent properties, it can cause small changes in initial hydrocarbon volumes (STOIIP). Conflicting indicators (different model parameters suggest different rock types) must be handled, which requires prioritizing in order to avoid inconsistency. Properly including the porosity-permeability correlations, priorities and model specific details, the rock type can bind all the geological properties together, which allows consistent parameter changes for an improved HM process.

This paper investigates a new workflow that improves the geological consistency of the process of assisted HM with a strong consideration of different geological constraints with respect to the different rock type definitions. The new workflow is provided as an external tool that can be applied as an extension for existing assisted HM workflows.
Evaluation of In-Situ Gelation Behavior by Slim Tube Technique for Deep Conformance Control
Authors: Wang Jinxun , AlSofi Abdulkareem M. , Alzahid Yara A. , Boqmi Abdullah M.
Published: November 2020

Gel-based conformance control is a potential method to ensure optimal contact with remaining oil in heterogeneous reservoirs. Conventional gel screening focuses on evaluating bulk gel properties, such as the gelation time and the gel strength. Evaluation of gel in-situ properties is limited to residual resistance after gelation (static property). A clear understanding of the gel dynamic properties in-situ is necessary for accurate performance evaluation and numerical upscaling of gel-based deep conformance control applications. In this study, we present a representative technique to evaluate polymer gel dynamic properties. Continuous gelant flow experiments are performed in an 80-ft long slim tube at reservoir conditions. The porosity of the slim tube is 37.0%, and brine permeability is 8.5 Darcies. Multi-point pressures along the tube are monitored to evaluate the variation in the gelant's ability to flow. The time-dependent permeability reduction and in-situ gelation time are determined based on the pressure responses. With which, we conducted a systematic study of in-situ gelation of an organically cross-linked polymer gel system at 95°C. A low molecular weight copolymer of acrylamide and acrylamide tert-butyl sulfonate was used in this study, which was crosslinked by polyethylenimine (PEI). Bottle tests conducted on gels with different polymer and crosslinker concentrations showed that the gelation time of the studied gel system can reach up to 10 days at 95°C. This indicates the potential of the studied organically cross-linked gel for deep conformance improvement applications. In the slim tube test, the polymer solution is injected before and after the gelant slug, which helps to diminish viscous fingering and maintain the gel-slug integrity. The in-situ gelation time, determined as the time when a clear shift (significant increase) in pressure drop buildup rate is observed, was consistent with that determined by the bottle tests. The slim tube technique presented in this study can simulate the propagation of gelants through porous media across long distances at actual reservoir conditions, providing essential data for the upscaling and design of gel-based deep diversion treatments.
Cost Effective Decommissioning Liability Solutions for Offshore Structures
Authors: Boondao Isara
Published: November 2020

The objective of this paper is to provide an outline of current decommissioning guidelines andtypical practices, and to explore cost effective ways in which companies can navigate through this multifaceted process. This is demonstrated via a revealing case study which illuminates an optimum, cost effective decommissioning methodology for offshore facilities and structures, which is closely aligned with emerging decommissioning guidelines and regulations and with industry best practices.

Decommissioning is governed by local regulations and is triggered by a number of specific factors, such as when the remaining reserves are less than 40%, or when the concession has a remaining period of less than 5 years, or in some cases when production has ceased. Normally, at some points in the process, security deposits are placed by the operator, which can be significant. Since this cost is seen as a liability and is based on an estimated decommissioning costs, a cost effective, yet regulatory compliant solution is required. This paper discusses various best practice technical strategies for decommissioning, which can be applied in the South East Asia (SEA) region, and throughout the world. The strategies proposed can result in an estimated operator saving of over 30% over the entire decommissioning execution expenditure. The processes that are discussed are included in the typical steps of preliminary design, detailed design and execution.