bluuebunny/crossref_metadata_2025 huggingface dataset:
De-Bottlenecking of Existing Flare System for Facility Up-Gradation using Dynamic Simulation Approach - Case Study
Authors: Wasnik Rakesh , Singh Harendra , Kamal Faris Ragheb , Takieddine Oussama Halim
Published: November 2018

In today's oil prices scenario, industry's focus is shifting towards Brownfield projects having low CAPEX utilizing existing Oil & Gas assets. Towards this objective, de-bottlenecking of existing flare system becomes inevitable for facilities up-gradation. The spare capacity of existing flare is utilized to accommodate additional relief loads from new facility, thus avoiding installation of new flare. Dynamic simulation approach provides significant advantages over conventional approach in terms of realistic estimation of flare capacity and optimal use of existing plant assets.

The conventional steady state approach assumptions provide conservative relief loads considering sum of instantaneous peak flows of relieving devices irrespective of their opening time. Flare operations are inherently dynamic in nature and dynamic simulations provide more realistic relief loads and presents optimal approach to de-bottlenecking of existing flare system.

Latest API approach to determine relief rate based on Fire Response Analysis using vessel rupture acceptance criteria also provides additional benefits in terms of relief load optimization as compared to conventional API approach to reduce the system pressure to 50% or 100 Psig in 15 minutes.

Dynamic approach also accounts for the packing effect in flare network, system operating pressure at which blow down will initiate and sequential opening of blow down valves for each isolatable section. Thus, dynamic approach provides better understanding of the dynamic behavior during blow down scenario. The flare system of offshore gas processing platform was originally designed based on steady state approach, commonly used being a conservative design which is more appropriate for green-field projects. In this approach, the total flare design load is established by adding all individual loads; assuming that peak flow from all sources will occur at the same time resulting in overdesign of flare system.

A dynamic simulation model was developed to analyze the behavior of flare system during emergency relief scenario incorporating the actual volumes of Flare KOD, sub/main flare header and actual opening time of blowdown valves. The dynamic approach accounts for the packing phenomena in the overall flare system network which significantly optimizes the design of flare system and associated equipment.

The results of dynamic approach are compared with conservative conventional approach. The study concludes that dynamic approach for flare system design provides more accurate estimation of peak flare load.
Dispersive Mode Processing of Borehole Acoustic Logs Using Fast Slowness-Frequency Inversion
Authors: Assous Said , Tudge Joanne , Whetton James , Elkington Peter
Published: November 2018

Shear slowness is commonly computed from well log dipole flexural mode data using slowness-time-coherence (STC) processing. Flexural dispersion is handled by restricting the signal's frequency content to the low frequencies that travel close to the formation's shear velocity, or by altering the phase relationships within the waveforms prior to STC processing in accordance with observed dispersion characteristics. Restricting the frequency range may not eliminate the need for a residual dispersion correction, however, and in noisy environments the dispersion curves needed for modifying phase relationships may be of poor quality. Formation and borehole properties have a significant influence on observed frequency content, and selection of bandwidth for the optimal balance between noise and size of the residual dispersion correction adds to overall processing time. Inversion addresses these difficulties by computing shear slowness directly from observed dispersion characteristics, but the process needs to be fast and tolerant to noise to be effective in commercial applications. In order to make the inversion efficient the iterative steps which compare observed and forward modeled dispersion curves are replaced with a fast neural net trained on a large number of pre-modeled curves generated with known formation and borehole properties. Automated mode frequency detection constrains the bandwidth over which dispersion curves are matched, accounting for potentially high levels of noise seen, for example, in horizontal wells. Results from 127,000 modelled and field data points show improved accuracy and precision relative to STC processing.
A Kinetic Simulation Study to Decrease Carbon Monoxide CO Emission from Sulfur Recovery Units SRU
Authors: Ibrahim Salisu , Rahman Ramees K. , Raj Abhijeet
Published: November 2018

To meet the regulations on the emission of toxic gases such as carbon monoxide (CO) and Hydrogen Sulfide (H2S) from the Sulphur Recovery Units (SRUs), a high amount of fuel gas is burnt in the incinerator to oxidize them that increases the sulfur production cost and CO2 emissions. This study investigates the major reactions that cause CO emissions and recommends possible solution to mitigate its formation in the SRU. The SRU simulations were conducted using a well validated and detailed reaction mechanism that captures the chemistry of CO and Sulfur species in the Claus furnace. The Claus reaction mechanism, containing 290 species and 1900 reversible reactions for the oxidation of H2S and the formation and destruction of COS, CO, CO2, hydrocarbons, and CS2 was used for reactor simulations, which was validated successfully using industrial plant data and the experimental data from lab-scale setups. The process parameters were varied to find the set of conditions that minimize CO production in the SRUs. The CO production in Claus furnace occurred through the high temperature decomposition of CO2 and CH4 present in the acid gas stream. The production of COS occurred from the reactions of CO with sulfur. The inlet temperatures of the feed gas streams (air and acid gas) were varied systematically to observe their effect on sulfur recovery and emissions of CO, SO2, COS, and aromatics. Upon decreasing the furnace temperature (by decreasing inlet air temperature) from 1105°C to 1050°C, CO emission from the SRU decreased by up to 60%, while sulfur recovery efficiency increased by 0.2%. However, the emission of aromatics (mainly benzene) increased by 3.5 ppm, while the more detrimental toluene, ethylbenzene and xylene were completely oxidized. Thus, maintaining an optimal feed temperature was found to minimize CO emissions from the SRUs, while maintaining high sulfur recovery. The simulation results predict the cost-effective solutions of minimizing CO and SO2 emissions from SRUs through the variation in process parameters that will help in reducing the consumption of fuel gas in the SRU incinerator.
New Engineering Approach for Environmental Impact Mitigation in Drilling Operations
Authors: Daoudi Adlane , Sator Salim , Samira Bellatache
Published: November 2018

Drilling waste generated during the drilling of wells using oil-based muds (OBMs) can often contain a high level of oily waste liquid as a result of surface mud losses, fluid displacements, rig wash down activities, and rig tank cleaning. This type of waste commonly known as "drilling slops" represents a significant volume of the overall waste generated while drilling a well and contributes to the overall environmental impact, cost of waste haul, and final disposal. In addition, the use of emulsifiers and other chemicals in OBMs leads to these liquids becoming difficult and expensive to treat efficiently with conventional separation and treatment systems.

This paper sets out a new method for treatment and recycling of this type of waste for land drilling operations that achieved a 73% reduction in waste volumes generated compared to other wells drilled in the same area. The results in the paper will also demonstrate that the oil and water recovered by this system was within the recommended quality parameters for recycling in the drilling operation. This system significantly reduces the need to transport wastes for offsite treatment and disposal while reducing the overall environmental impact of the drilling operation.

After analyzing the source of wastes generated during drilling at a land location in Algeria, a methodology was devised to segregate drilling wastes and avoid the co-mingling of different waste types before sending the drilling slops to the system for treatment. Lab tests were carried out to determine the optimum flocculants and dosing rates required to separate and recover the oil and water from the solids. This new method for treating and recycling these waste is an integrated chemical flocculation and dewatering system using a container fabricated from a specially engineered textile that provides confinement and drying of drill solids inside the container while allowing the liquids to permeate through the engineered textile for recycling and reuse on the rig. This system reduces the amount of liquid wastes hauled off site for treatment leaving dried solids that are easily handled and disposed of with conventional treatment methods.

The use of this technology can have an important and cost effective contribution to reducing the environmental impact of land drilling operations using OBMs in Algeria and beyond.
Blended-Acquisition Encoding with Generalized Blending Operators: Signaturing with Temporally Amplitude-Modulated and Spatially Dispersed Source Array
Authors: Ishiyama Tomohide , Ali Mohammed , Blacquiere Gerrit , Nakayama Shotaro
Published: November 2018

Recently, we established a generalized blending model, which can explain any methods of blended acquisition by including the encoding into the generalized operators. With this highly flexible and tolerant model, we come up with a challenging question: what it is to be, and how to find an optimal blended-acquisition design, which should be the most suitable for deblended-data reconstruction among plenty of concepts of blended acquisition. In this paper, we introduce a method of blended-acquisition encoding: temporally modulated and spatially dispersed source array, namely M-DSA, that jointly uses modulation sequencing in the time dimension and dispersed source array in the space dimension. This allows quite straightforward deblending by filtering and physically separating frequency channels in the frequency domain.

We run our blended-acquisition designing based on the deblending performance for several scenarios of blended acquisition. These examples show that: M-DSA attains the best deblending performance; this method has less constraints in the encoding with more operational flexibility, compared to other methods being developed in the industry today. Indeed, this method requires only simple signaturing in the encoding; merely frequency-banded and modulated signatures in the time dimension for each shot in the blended-source array. This could even render any other blending properties unnecessary. Those, such as distance separation among shot locations and time shifts among shot times, might not be required anymore. There might be no limitation on the number of sources, thus no limitation on the blending fold, in order to secure successful deblending. Furthermore, this method allows random sampling; randomly distributed sources in the space dimension in the blended-source array. Consequently, this method makes the blended-acquisition encoding and operations significantly simple and robust, as well as for the deblending processing. We believe that our M-DSA method should be one of the best methods of blended acquisition.
Tight Reservoir: Characterization, Modeling, and Development Feasibility
Authors: Salahuddin Andi A. , Al Seiari Jamila M. , Al Shehhi Abdulla S. , Al Hammadi Khaled E.
Published: November 2018

The distribution of reservoir quality in tight carbonates depends primarily upon how diagenetic processes have modified the rock microstructure, leading to significant heterogeneity and anisotropy. The size and connectivity of the pore network may be enhanced by dissolution or reduced by cementation and compaction. Consequently, a clear understanding of the diagenetic process that responsible for the reservoir tightness would offer vital assurance on the spatial property distribution and future field development plan. In this paper, we have examined the factors which affect the distribution of porosity, permeability and reservoir quality in the Thamama Group, which is a prospective low permeability carbonate reservoir rock in Onshore Abu Dhabi.

The dataset includes regional stratigraphy, well logs and core material from a number of wells, a suite of laboratory petrophysical measurements, seismic attributes, geomechanics, fracture study, and production history. Dataset analysis and interpretation suggested that the reservoir was deposited in shallow to deep marine low energy environment which led to deposition of fine to very fine grains (lime-mud supported) types of sediments. This, in turn, would produce poor reservoirs during compaction and finally leads to tightness.

Because of the low permeability nature of this tight reservoir, it is quite challenging to obtain their complete reservoir properties and dynamic behavior. As in many other tight reservoir projects, a considerable area of the reservoir must be effectively stimulated during the hydraulic fracturing process to achieve economic productivity. In addition, development of tight reservoirs often faces challenges, for example, low initial production rates and high declining rate.

This paper aims to frame all possible optimum development practices for tight reservoir in the studied field that should be considered for future development plan. We also investigated the application of new technology to enhance the poor oil recovery within the pool including horizontal drilling and multi-stage fracture completion technology. Furthermore, this paper also discusses well orientation relative to the far field principal stresses, hydraulic fractures treatment, fracture fluid selection, and nano-technology application. This, in turn, would provide valuable information on how to optimally develop this previously considered marginal and uneconomic reservoir.
The Application of Refracturing Technique in Horizontal Wells of Daqing Oilfield
Authors: Wang Xianjun , Wang Wei , Li Borui , Li Dongxu , Gu Mingyong , Tang Pengfei , Zhang Hao , Liu Yu , Li Yonghuan , Wang Jing
Published: November 2018

Aiming to the development of the tight reservoirs with low permeability in Daqing Oilfield, the horizontal well fracturing technique has achieved good results. However, the output gradually decreases later. The initial average daily oil production per well is 17.0t and drops to 2.6t after some time. Also, the wells with the production lower than 2t constitute more than 50%. Thus, to realize the economic and effective exploitation, the refracturing technique is needed to improve the production.

According to the geological and producing conditions, two optimization methods have been formed, including the chart method and the dynamic method.

Based on cement quality and wellbore integrity of horizontal wells, 2 kinds of refracturing pipe strings including the double-packer isolation refracturing one and the single-packer isolation refracturing one have been formed. Besides, based on the initial fracturing parameters and completions, 4 refracturing modes are formed aiming to 4 scenarios including inadequately fractured stages, new fractures supplement, diverter refracturing within the fractures and multi-stage diverter refracturing, and are carried out for field tests.

(1) Small-scale initially fractured wells can be treated by the massive in-situ refracturing and 15 wells field tests are carried out. Compared with the initial fracturing, the sand amount and fracturing fluid are increased by 58% and 145% respectively and the daily oil production increases from 0.4t to 4.2t after refracturing.

(2) The wells having sparse initial fractures can be treated by refracturing to infill new fractures and 13 wells field tests are carried out. Compared with the initial fracturing, the gaps among fractures are reduced by 54.7%, and the daily oil production is increased from 1.7t to the 4.6t after refracturing.

(3) The wells with small angles formed by two directions between initial artificial fractures and wellbore can be treated by the diverter refracturing and 3 wells are treated by this to increase the production from 1.63t to 5.33t.

(4) 2 wells having not been sectionally fractured in light of their poor cement quality have been treated by the diverter refracturing within the scope of the whole wellbore, with the production increased from 1.5t to 4.5t.

In general, the daily oil production of 33 wells is averagely increased from 1.1t to 4.5t, which reaches 70.4% of the production after the initial fracturing.
Optimizing Stringers Development Using Latest Probabilistic Seismic Inversion Technique
Authors: Al-Busaidi Ahmed , Qureshi Tahira , Al-Naamani Ali , Al-Abri Mohammed
Published: November 2018

The A2C carbonate reservoirs are known to be the most complex sour gas reservoirs in South of Oman. These reservoirs are considered to be tight with varying porosities. The main challenge with the Asset is to identify high porosity layers with sufficient net thickness. The previous QI work done on newly available 2016 PreSDM Wide Azimuth (WAZ), provided the acoustic impedance derived porosities for sweet spotting. However, it was not able to characterize the net pay thickness due to limited vertical resolution of the inverted porosity cube.

The present model-based probabilistic seismic inversion was carried out on 2016 PreSDM Wide Azimuth (WAZ). It combined the rock and fluid properties, and prior knowledge from static reservoir model and provided porosity realizations that are consistent with seismic. The Porosity from inversion provided better vertical and lateral resolution and the uncertainty associated with it. The high resolution porosity model highlights possible sweet spotting zones and appraisal opportunities. The updated porosity models using this latest technique shows details that enable better understanding of the reservoir performance and optimizing future development.
Water Treatment Challenges to Meet BFW Spec Using Reject Streams from Municipality Sewage Plant - Kuwait
Authors: Kuijvenhoven C. A. , Ghouti R. , Alenezi M. Z. , Al Rasheedi R. A.
Published: November 2018

Water from the reject stream of the Reverse Osmosis (RO) units in Sulaibiya Waste Water Treatment plant (SWWTP) will be used as source water for the Once-Through Steam Generators (OTSG) for the South Ratqa (SR) Phase I project. Using sewage water as source water for steam boilers directly impacts the complexity of the water treatment processes.

Based on the South Raqa steam quality specifications, a water quality requirement has been defined which was found in line with international guidelines. For one of the quality requirements specified (Chemical Oxygen Demand) a tight specification of < 0.1 mg/l was set, which is not often seen in the industry. Instead the industry does define Total Organic Carbon (TOC) as water quality specification, which is closely related to COD. As the water source in the Sulaibiya is coming from a sewage plant (unknown organic components), COD was included as water quality specification.

To deliver the required BFW quality, seven different treatment steps are being installed, which all need to be optimised to ensure the required high plant availability. The major risk area is the requirement to achieve residual chlorine in the water stream coming from the Sulaibiya plant.
Employing Lean Practices in Well and Reservoir Management to Optimize a Thermal EOR Development, Sultanate of Oman
Authors: Shaqsi Khadija Al , Alwazeer Abdullah , Belghache Abdesslam , Mawali Shaikha Al , Sawafi Marwan Al , Aulaqi Talal Al , Bulushi Badriya Al , D'Amours Kevin , Yahyai Ahmed Al , Yazidi Rashid Al , Hilali Ali Al , Zaabi Yousuf Al , Hinai Jaifar Al , Mujaini Rahima Al , Gheithy Ali Al , Bettembourg Solenn
Published: November 2018

This paper describes how the deployment of multiple Lean projects by Petroleum Development Oman's Thermal Well and Reservoir Management (WRM) team has resulted in significant cost savings, in terms of efficiency and oil production.

WRM teams are an integrated group within production assets, comprising of petroleum, process engineers, operations staff and well services. Supported by data acquisition and interpretation, the teams are responsible for operating and optimizing the field.

Historically, Petroleum Development Oman's Thermal WRM team faced some challenges such as data access and activity processing including pattern reviews, Cyclic Steam Stimulation (CSS) planning, business planning and operational routine activities such as fluid levels. In addition, key surveillance activities suffered from delays and data interpretation inaccuracy. The above resulted in significant time inefficiencies and deferred oil production.

The continuous improvement initiatives started in 2015 with a particular focus on improving thermal WRM process. A deployment plan was created starting with identifying the need and clarifying the required steps to earn the Lean status as defined in PDO. Lean Management System (LMS) was defined followed by awareness sessions. These initiatives resulted in the identification of many opportunities for continuous improvement and Lean initiatives.

Multiple improvement areas were identified against a set of measured baseline conditions. The following projects were selected for Lean: Integration pattern reviews improvements.CSS optimization by monitoring key reservoir management indicators.Reduction well intervention cycle time in CSS.Exception based automation of reservoir surveillance tools.Visualization of CSS workflow and efficiency enhancement.Production forecast automation.Automation fluid level above pump for well optimization.

Four of the above projects were successfully completed in 2016 and 2017, with the remaining were completed in 2018. Below are highlights of implementing Lean projects in PDO: ∘Estimated 70% manpower time saving.∘Approximated 5% incremental oil gain.∘Anticipated 42% reduction in unscheduled deferment.∘Confirmed 80% waste reduction in overall forecasting, CSS workflow and steam flood monitoring process.∘Eliminated the need for manual fluid level shots, reduced HSE exposure due to travel.

Improved tracking of CSS activities reduced operational errors. A thermal economic dashboard was also introduced to rapidly identify sunk costs, minimize Unit Technical Cost and improve Cash Flow.
Enhancement of Dry Gas Seal Reliability
Authors: Sahadevan Roy , Al Menhali Basma
Published: November 2018

Objective

Shaft sealing prevent uncontrolled escape of process gas from the gas compressor casing. During shaft sealing failure, apart from loss of production, consequences due to loss of containment of hazardous and toxic process fluid may extend to multiple fatalities and major asset damage. Due to this high risk, the operation team is highly focused in improving reliability of compressor seals.

Over the years, traditional oil film seals are replaced by dry running gas seals. Most of the process gas centrifugal compressors manufactured today are equipped with dry gas seals. Dry gas seals are available in a variety of configuration; the most common one for process gas application is tandem seals.

This report describes a centrifugal compressor dry gas seal (tandem seal) failure investigation in an oil and gas field and the recommendations to enhance gas seal reliability.

Dry gas seals in a medium pressure, hydrocarbon gas compressors had experienced frequent failures, to be precise, five dry gas seals failed in a span of seven months. These frequent failures become a serious challenge to sustain gas production.

Analysis

Data for analysis was gathered during site visit, in addition, discussion with operations & maintenance team was held to understand equipment performance and maintenance status. Real time operational data was obtained from data server for selected parameters.

Defect elimination is the method used for analysis, this include identifying all possible causes of failure. The trends on key operating parameters that have the potential impact on seal failure and the variation of these parameters during the event are analyzed. The report describes the details of analysis performed.

Results and conclusions

An evidence based approach is used either to qualify or eliminate the cause of failure. The report indicates the most likely cause of seal failure based on the method of analysis.

This report describes the modifications in the system and operating requirements to prevent future dry gas seal failures. Modification includes additional instrumentation for monitoring to increase safety of existing equipment and systems.

Site utility conditions, compressor operating conditions, control and monitoring of key parameters can significantly influence dry gas seal reliability and requires special care in the design of seal auxiliary systems. By providing proper training to operators and maintenance team the seal reliability can be enhanced.

Dry gas seals in critical rotating equipment are very common in the oil and gas industry. Seals can fail for a variety of reasons, hence improving reliability of gas seals is important for the operations to achieve hydrocarbon production targets.
Screening of New HPAM Base Polymers for Applications in High Temperature and High Salinity Carbonate Reservoirs
Authors: Alfazazi Umar , AlAmeri Waleed , Hashmet Muhammad Rehan
Published: November 2018

Application of polymer flooding technique under extreme reservoir conditions (~120°C and 167000 ppm) is still of great concern. In high temperature and high salinity (HTHS) reservoirs, the commonly used polymers for improved oil recovery purposes are ineffective due to chemical degradation and poor injectivity. Therefore, the aim of this paper is to screen partially hydrolyzed polyacrylamide (HPAM) base polymers in order to find suitable polymer for a targeted HTHS carbonate reservoirs.

Polymer screening study was carried out on three new NVP-HPAM base polymers to identify a potential candidate which can withstand harsh reservoir conditions. Initially, a comprehensive rheological study was conducted at various polymer concentrations (1000-4000 ppm) and brine salinities to investigate the effectiveness of the polymers. Then, thermal stability test was conducted at anaerobic condition and 120°C for three months. Finally, injectivity test was conducted with the best polymer and in the absence of oil at 120°C and formation salinity (167000 ppm). The experiment was done by sequential injection of 3 polymer concentrations (3000, 1500, and 750 ppm). Parameters such as resistance factor, residual resistance factor, insitu rheology, and apparent shear rates were investigated during the experiment.

Results from the rheometric studies showed that all three polymers have acceptable initial viscosifying properties at ambient temperature and shear thinning behaviors within shear rate range of 1-100 s-1. The results also indicated that polymer viscosities dropped with increase in temperature and salinity. However, they still showed good resistance up to 167000 ppm and 120°C. The thermal stability test for the potential polymer showed better stability and retained more than 90% of its initial viscosity after the ageing period. Whilst injecting at 3000 ppm, the resistance factor (RF) was between 20-10 (at different flowrates). During 1500 ppm and 750 ppm, the RF were in the range of 14-6.5 and 5-2.7 respectively. At low flowrates (0.05-1.0 cc/min) of polymer injection, shear thinning behavior was observed. Whereas, shear thickening behavior at high flowrates was observed at all concentrations. Finally, the residual resistance factor (RRF) recorded for the injectivity experiment was found to be 6.17.

The potential polymer showed promising results for its application in heterogeneous carbonate reservoir with higher temperature and salinity of 120°C and 167,000 ppm respectively. The study also leads to better understanding of polymer flow behavior in high temperature high salinity carbonate reservoirs.
Drilling Automated Realtime Monitoring Using Digital Twin
Authors: Gholami Mayani Maryam , Rommetveit Rolv , Oedegaard Sven Inge , Svendsen Morten
Published: November 2018

Having a Digital Twin of the drilling well, pairing digital and physical data combined with predictive analytics and diagnostic messages, improves accuracy in planning and decision making of the drilling operation. It helps the industry to increase safety, improve efficiency and gain the best economic-value-based decision as well as reduce operational cost. Today advanced monitoring is normally done using real-time measurements, compare pre-simulation results with measurements, perform manual diagnostics and run new simulations when abnormalities are seen. All done manually by people.

Drilling can move beyond advanced monitoring using Digital Twin's by implementing automatic ‘forward-looking’ and multiple ‘what-if’ simulation to give operations the optimal plan with focus on safety, risk reduction and improved performance.

The Digital Twin examples in the current paper can do more advanced and complex automatic forecasting simulations, diagnostics, ‘forward-looking’ and ‘what-if’ simulation as well as predictive analytics in the wellbore in the 2D and 3D simulation view.

By using the advanced models (Digital Twin), all relevant challenges and risks were identified during the drilling operations of one well under high pressure high temperature (HPHT) conditions. The stand pipe pressure (SPP), equivalent circulating density (ECD) and temperature behavior were studied during the drilling and circulation of this well. The Digital Twin was also used to evaluate possible losses during 9 7/8″ casing running and cementing with special focus on when casing was passing through the formations. In another well the Digital Twin triggered an early notification regarding high cuttings concentration during drilling 8 ½″ section. The flow rate was adjusted and helped to prevent sidetrack and pack-off due to losses.

Morover during drilling 17 ½″ section in another case, large losses were prevented by comparing the modeled active pit calculation and measured tank volume. The Digital Twin enables advanced automatic forecasting simulation, self-diagnostics, automatic ‘forward-looking’, multiple ‘what-if’ simulation and predictive analytics to improve safety, reduce risk, increase drilling performance and reduce costs.
Increasing Stimulated Reservoir Volume SRV in Unconventional Reservoirs: Microstructural and Rock Mechanical Study
Authors: Mustafa Ayyaz , Tariq Zeeshan , Abdulraheem Abdulazeez , Mahmoud Mohamed , Al Nakhli Ayman , BaTaweel Mohammed
Published: November 2018

The huge resources of unconventional hydrocarbon reserves across the world coupled with the growing oil value makes their contribution to be significantly important to the world economy. Oil producing companies can invest in unconventional hydrocarbon to cover local demand and save crude oil for exporting. Conversely, one of the foremost challenge that producers face in unconventional reservoirs is the need for large stimulated reservoir volume (SRV) to ensure economical production.

This study describes a new stimulation technique to increase the stimulated reservoir volume using the chemical reactions along with hydraulic fracturing fluid. Reactive chemicals are used to generate the localized pressure and heat in tight formations to create additional micro fracturing, thus increase the fracture complexity. Created induced micro-fractures considerably increased the porosity, permeability, and ultimately the SRV. The synthetic sweetspots are created nearby a wellbore and fractured area by the help of new stimulation treatment mechanism. Results showed significant conductivity increase with new treatment technique.

Rock samples were studied for mineralogical and microstructural characterizations using advanced spectroscopy and microscopy analytical techniques. Moreover, on each rock specimen ultrasonic compressional (P-wave) and shear (S-wave) velocities were recorded and dynamic Poisson's ratio and Young's modulus were determined. The obtained topographical images revealed the presence of micro-cracks and nanoscale pores in all studied core samples.

The novelty of this study is to develop a novel fracturing technique to increase stimulated reservoir volume (SRV). The parameters studied in this research can be served as critical inputs for many field applications such as wellbore stability, casing design and perforation, sand production control, and fracturing.
Targeting the Permo-Triassic Tight Gas in the Khuff: Lessons Learned in the Journey towards Development, Offshore Abu Dhabi, UAE
Authors: Steiner Stefan , Dasgupta Suvodip , Basioni Mahmoud , Al Aryani Fatima , Noufal Abdelwahab , Mills Carey , Mandl Johannes , Menon Pradeep , Raina Ishan , Mosse Laurent , Shasmal Sudipan , Hollaender Florian , Ali Humair , Al Afeefi Baraka , Sookram Neil
Published: November 2018

Exploration drilling for gas potential in Khuff Formation started more than 40 years ago and wells across multiple assets in offshore Abu Dhabi showed the presence of sizeable reserves. With increasing recent importance on gas production, there is a plan for moving towards development for those Permian tight gas structures to address the nation's gas needs. This paper will try to address the lessons learned from the recent appraisal wells in Khuff, the uncertainties and the success criteria.

There have been multiple wells drilled through the Khuff Formation in Offshore UAE in the last two years and have yielded a wealth of information from downhole well logs, mud logs, well test results and core data. The downhole logs acquired in these wells ranged from basic triple-combo and mud logs to image and dipole sonic logs, along with formation testing and sampling measurements, followed by well tests across the zones of interest. Interpretation of all these data have revealed some interesting lessons learned.

The shallow marine sequence of the Khuff Formation is generally characterized by poor porosity and low matrix permeability; however, the diagenetic overprint has resulted in a significant heterogeneity development, which controls the present-day porosity and permeability development at the wells. The well test results show variations in terms of 2 or 3 orders of magnitude at the same interval, which highlights potentially problematic development strategies. We have observed significant differences in terms of lithology, porosity and other reservoir quality indicators between wells, located a kilometre apart. Optimization of logging suite to minimize petrophysical evaluation uncertainty will be discussed. Characterising this heterogeneity is key for future economic success of this play. Possible role of fractures influencing flow from the Khuff have been discussed in older publications, however no conclusions were arrived at, with certainty. Presence of fractures and faults beyond the immediate vicinity of the well might be something to look at, in terms of understanding the potential productivity of those intervals. A big step for developing Khuff Formation might be in terms of deciding the optimal stimulation strategy and this is something, which remains to be studied extensively in UAE.

Closing the loop of interpretation of the acquired logs with the final well-test results and production logs gives us the advantage of hindsight and helps us in separating out the key productivity indicators as well as bring out the uncertainties in formation evaluation, which affect these tight gas reservoirs.
A Novel Dynamic Assessment of Multi-Stage Hydraulic Fracture Propagation in Presence of Natural Fractures in Shale Gas Reservoirs
Authors: Suboyin Abhijith , Rahman Md Motiur , Haroun Mohamed , Shaik Abdul Ravoof
Published: November 2018

Augmented by the recent activities in unconventional reservoirs, it can be easily said that hydraulic fracturing has become a pivotal component for the successful development of unconventional reservoirs. This novel study deals with the investigation of fracture propagation behavior in shale gas reservoirs under varying controllable and non-controllable parameters. In addition to the analysis of propagation behavior, their interaction in the presence of natural fractures are reviewed and quantified.

It is highly challenging to quantify and address the distinct contributions of an element due to the level of heterogeneity that is present in reservoirs. In-situ stress has been reported to be such a dominant contributor to the fracture propagation behavior as they are imperative to assess the extent and the direction of fractures. An enhanced dynamic simulation was conducted to investigate fracture propagation behavior in shale gas reservoirs under varying parameters which were categorized as controllable and non-controllable with respect to the fracture design, treatment and drilling process. After an extensive assessment, a set of natural fractures were introduced to the system and the system behavior was further analysed.

The constructed model is verified with traditional and published models to validate the generated results. It is illustrated that even modest variations of the associated principal stresses between the target zones and the bounding zones can severely limit hydraulic fractures. Further simulation runs under varying fluid conditions and its associated properties revealed similar observations. With the introduction of natural fractures, it is demonstrated that the distribution of the natural fracture network plays a critical role in the cumulative gas production along with its description. Additional investigation illustrates and verifies that fracture width assists in better performance as compared to fracture length for the defined conditions. Fracture placement along with its orientation and proppant properties are also considered to further examine the associated response on productivity.

This novel investigative approach will create a paradigm for future studies that will assist in a simplified prediction of fracture propagation behavior, its associated drilling parameters and anticipated response. In addition, an extensive investigation for the quantification of changes with respect to the variation in prime contributors is presented, which assists in the validation of modern best practices approach.
Reservoir Ranking Map Sketching for Selection of Infill and Replacement Drilling Locations Using Machine Learning Technique
Authors: Li Yuanjun , Samuel Robello
Published: November 2018

Infill and replacement drilling are effective ways to improve oil recovery as increasingly more wells are drilled in close proximity for fracturing. Presently, the approaches being employed are logging surveys, the moving window method, the rapid inversion method, and the customized type curve method. However, these methods are not suitable for reservoirs with high levels of heterogeneity in terms of geology, and require more expert knowledge and field survey, which can be time consuming and costly. Therefore, the present method developed is an economic and fast approach to determine infill and replacement drilling location from reservoir ranking maps generated in combination with machine learning methods.

During this project, production data and reservoir parameters were gathered from an old oil field with more than 2,500 wells where most of the field was under water injection. Bubble maps were created for each reservoir parameter for a better visual representation of reservoir conditions. Then, after data cleansing and normalization procedures, the standout attributes were identified from all given reservoir parameters and production history and a reservoir ranking rule was set. Next, five types of classification approaches were used for prediction. This paper additionally presents a regression method, artificial neural network (ANN), to compare with the prediction results from classification. For each machine learning technique, a reserve ranking map was generated for this test field to predict future infill drilling and replacement drilling opportunities. Thus, with only geographic coordinates, the reserve ranking level was obtained.

From cross-fold validation results, a quadratic support vector machine provides the highest prediction accuracy. From a practical standpoint, a decision tree offers a more realistic result. In addition to the ANN method outputs, the ranking result provides a smooth method between certain levels. This new approach of using artificial intelligence was used to provide the ranking level and ranking number to identify the best options for drilling the wells, which is different from the present traditional methods. This advanced reservoir ranking map allows operators to identify the best location for infill or replacement drilling. It can additionally help operators benefit from their previously gathered knowledge in a cost-effective way.
A Novel Power Generation System Utilizing Un-treated Sour Gas Fuel
Authors: Xijia Lu , Miles Palmer , Brock Forrest , Mike McGroddy
Published: November 2018

A significant portion of natural gas reserves around the world contain large quantities of sulfur species and carbon dioxide, which are often referred to as sour gas reservoirs. The IEA reports that more than 40% of the world's gas reserves are sour, with the number increasing to 60% for Middle Eastern gas reserves. Sulfur species, such as hydrogen sulfide (H2S), are highly corrosive when mixed with water and toxic to biological organisms. Compounds such as SO2 and SO3, which are derived from direct sour gas combustion, are also highly corrosive when mixed with water at the condensation temperature of sulfuric acid. Therefore, removal of H2S to trace levels from natural gas is typically considered as the first step of the utilization of sour gas for power generation. This paper presents a novel method which enables sour natural gas to be directly burned for power generation without pretreatment. Oxidized sulfur compounds are captured by limestone in the combustion process to eliminate downstream sulfur corrosion. The desulfurized flue gas then goes through a solids removal process before entering a gas turbine or a turbine expander for power generation. A steam cycle is used for waste heat recuperation from both the turbine exhaust stream and the solids stream to improve the cycle performance. Both air-combustion and oxy-combustion configurations were investigated and modeled using Aspen Plus. The design conditions of each cycle are within the operating envelope of commercially available equipment, including compressors, turbines and heat exchangers, enabling near-term deployment of the presented system. Aspen modeling results show the range of efficiency percentages for different cycles is from the low 40's to the low 50's on a Lower Heating Value (LHV) basis. Without pretreatment, the heating value of sulfur in the sour gas and the heat released from the limestone scrubbing process can be fully utilized for power generation, thus improving the cycle performance. Economic analyses estimate that the baseline air-combustion sour gas system with a conservative estimated Capex ($2142/kW) is 41% cheaper than NGCC in 2011, and is about 28% cheaper than advanced NGCC in 2022 on a simplified Levelized Cost of Electricity (LCOE) basis. The LCOE of the oxy-combustion sour gas system is estimated to be 53% lower than advanced NGCC in 2022 when the revenue from CO2 and Argon sales is taken into account. Therefore, the novel untreated sour gas combustion system presented in this paper enables the petroleum and power industries to use sour gas for power generation more efficiently and cost effectively, even with full carbon capture.
An Innovative Technique to Sustain Well Performance
Authors: Channa Zohaib , Al Qubaisi Salama , Al-Neaimi Ahmed Khaleefa , Al Syari Ahmed Mahfoudh , Al-Shehhi Omar Yousef , Nofal Salman , Khan Mohamed Navaid , Ahmed Fazeel , Khemisa Hocine , Al Feky Mohamed , Abdel-Aziz Mahmoud , Gutieirrez Freddy , Obeid Ahmed Fayyad
Published: November 2018

In the case study field, most of the wells are being completed with dual strings where there is no accessibility in the upper zone (short string). This leads to no well intervention in the future if there is any gas or water breakthrough or in some cases the formation collapse. However, formation collapse was recently observed in the certain dense (impermeable) layers which are liable to hole collapse when in contact with HCl acid during stimulation operation hence resulting in hole plugging. This leads to losing the production / injection from the upper zone and requires rig workover to clean out and recomplete the well. This phenonmenon was further confirmed by several experiments performed on different core samples in the Lab. A quick and cost effective solution was looked into and found that 4-1/2" liner, called "drop-off", can be run and set in the upper drain of the well to avoid any future breakthroughs or hole collapse. 4-1/2" drop-off liner was successfully run in multiple wells and proved to be very efficient. This cost effective innovative technique resulted in restoring the wellbore stability and help in sustaining the production from the upper drain.
Well Design Evolution, Validation and Optimization in ADNOC Onshore GAS Field
Authors: Yugay Andrey , Gadelhak Abdelrahman Mohamed , Pimenta Gervasio , Al Reyami Mariam Mansoor
Published: November 2018

In early 80's in ADNOC Onshore standard well completion design for gas producers in Reservoir Y of Bab field was a combination of L-80 carbon steel with a downhole continuous corrosion inhibitor injection above the Chemical Injection Valve (CIV) and Corrosion Resistant Alloy (CRA) Incoloy 825 / SM25Cr-75 below the CIV and packer.

In 1994 (after 10 years of operation), due to the fact that no integrity issues were observed, it was decided to maintain the same design strategy was followed in all new gas producer wells in this reservoir. Identical design strategy was followed for Reservoir X (Project-I) gas wells which presented less severe fluid conditions. Table 1 summarizes reservoir conditions for both reservoir X and Y.