bluuebunny/crossref_metadata_2025 huggingface dataset:
Fit-For-Purpose Model for Dielectric Data Interpretation for Enhanced Formation Evaluation
Authors: Abdallah Wael , AlZoukani Ahmed , Al Hamad Mohammed , Ma Shouxiang
Published: March 2023

Great progress in technology development of dielectric logging has been made in the last decade, mainly by establishing the capability of multi-frequency measurements for more robust determination of near wellbore water-filled porosity and flush zone resistivity, in addition in providing the potential of characterizing reservoir petrophysical properties such as rock tortuosity. To interpret acquired dielectric data, several models have been developed and used in the industry. The objective of this laboratory study was to evaluate the commonly used models, identify conditions under which each model is applicable, and establish a workflow to select the most suitable model for targeted applications.

This study was performed on limestone core samples. Routine and special core analysis including resistivity and dielectric measurements were conducted. Three commonly used dielectric models (CRIM, Bimodal, and SMD) were evaluated. Properties having major influence on these models are brine salinity, brine saturation, and Archie parameters m and n. Effects of these properties on the dielectric data interpretation models were studied systematically, by comparing the models’ outputs to direct laboratory measurements. For core samples fully saturated with fresh water of salinity ranging from 2 to 23 kppm NaCl, all three models provide consistent results of inverted water-filled porosity when compared with core weight porosity. The inversion results are robust and independent of whether the salinity is constrained or not. In a saline environment of 200 kppm NaCl, the inverted water-filled porosities are found to be slightly higher than core porosity. Comparing between inverted dielectric textural parameter MN and Archie resistivity parameter m shows that the Bimodal model performs better than the SMD model at this high-water salinity environment.

Based on these results, a simple linear regression correction scheme is proposed for each salinity range investigated. The proposed algorithm is structured to correct the output of each model using statistical mean at specific salinity conditions. Finally, we introduce a fit-for-purpose model selection for dielectric data interpretation for enhanced formation evaluation.
Estimation of Missing Molecular Weight and Specific Gravity of Heptane Plus Fraction in PVT Laboratory Report
Authors: Al-Marhoun Muhammad
Published: March 2023

The molecular weight and specific gravity of heptane plus fractions (C7+) are essential in characterizing crude oils. The hydrocarbon analysis of reservoir fluid test usually reports molecular weight and specific gravity of C7+ in the PVT report. Sometimes these values are missing; therefore, estimating them is crucial. This study aims to develop new empirical correlations to estimate the missing molecular weight and specific gravity of the C7+. The experimentally measured hydrocarbon analysis of reservoir fluid tests from the Middle East crudes is the basis for developing the correlations. The input parameters for the correlations are available molecular weight, the specific gravity of C7+, and stock tank oil-specific gravity. The newly developed correlations outperform the existing correlations based on high correlation coefficients and low values of average absolute percent relative error and standard deviation.
Operational and Logistical Optimizations in Large Offshore Matrix Acid Stimulations
Authors: Saleh A. A. , Bukhamseen R. , Jaber A. A. , Almazrou A. H.
Published: March 2023

Objectives/Scope: This paper addresses the complex logistical challenges associated with the planning and execution of a large-scale offshore matrix acid stimulation treatments job performed on a small workover rig. It captures the challenges and the smart solutions deployed as an example, and quantitatively reflects on how the adopted solutions improved the operations in terms of achieving the technical objectives, minimizing job duration, rig space utilization and safety.

Methods, Procedures, Process: Offshore acid stimulation complexity rapidly multiplies whenever larger volumes of acid are involved. Our example reviews an offshore matrix acid stimulation where, for the first time within the region, more than 1300 Bbl of acid treatment was placed across a reservoir in an offshore workover rig, while a typical offshore workover rig matrix acid stimulation will not exceed 300 Bbl treatment. To address the challenges associated with such large offshore matrix acid stimulation jobs, a number of key methodologies were adopted. Most importantly, tailored fit measurements of available rig space and choosing the most suitable equipment's layout and acid tanks having the required dimensions, capacity and weights, were all, of crucial importance considering the limited workover rig space with other CTU and N2 services also present.

Results, Observations, Conclusions: A unique and complex offshore matrix acid stimulation treatment was successfully completed where 1326 Bbl of acid treatment was pumped across target reservoir with zero hours NPT and zero LTI. Careful planning, strong communications and close coordination between all parties involved were the fundamental elements to the success of this operation. It was also noted that selective premixing of chemicals at service company base enabled further optimizing of rig space utilization and a reduction of operational risks and rig time. Hence it can be concluded that with proper planning and careful consideration of the details, such large offshore matrix acid stimulation jobs can be more frequently deployed in offshore workover rigs which will have positive impact on well productivity and performance.

Novel/Additive Information: This large-scale offshore matrix acid stimulation treatment job was a first of its kind within the region in terms of job complexity and acid volumes, it is a good reference to many lessons learned and it opens the door for a new and wider horizon of applications for offshore matrix acid stimulation technologies.
Reservoir Simulation Evaluation of Cyclic Steam Stimulation Strategies in Tayarat Carbonate Heavy Oil Reservoir
Authors: Evro Solomon , Alshamali Adnan , AL-Faresi Fahad , Mishari Al-Qattan , Al-Ostad Nejoud , Krasnova Galina , Hayat Laila , Suresh andana , Mandani Hasan , Jimenez Carlos , Ali Sher
Published: March 2023

The Tayarat formation extends over a large area; this formation has a diverse and complex geology and has heavy oil fluid system. A previous review of the analogous technologies that apply to the Tayarat heavy oil formation shows that it would be economically impossible to deploy a single reservoir development technology in all the areas of the field. In this project, we evaluated cyclic steam stimulation strategies focusing on applying different well completions.

We have applied a compositional numerical simulation model using CMG Stars to investigate the application of different cyclic steam stimulation strategies. This includes using a traditional vertical well with a single steam injection point in the entire zone of the reservoir. We also investigated the use of vertical wells with dual string completion, where the short string injected into the upper parts of the formation while the long string injected into the lower part of the reservoir. With the horizontal well injection, we investigated open-hole completion and the case of using a horizontal well with multi-stage hydraulic fracturing.

The potential of injecting steam at a higher rate with horizontal wells is attractive and requires more investigation. Apart from reducing the well count, we could overcome the surface constraints challenge in the field by stepping out of the congested areas and placing the horizontal section in the targeted part of the formation. With the advances in horizontal wells with multi-stage hydraulic fracturing in the industry, carbonate reservoirs such as Tayarat with low permeability could benefit from more reservoirs contact and possibly better steam distribution if we introduce adequate hydraulic fracture stimulation in the formation.

The results of this study show that we could reduce our drilling footprint substantially by implementing a horizontal well with multi-stage hydraulic fracture stimulation in developing parts of the Tayarat carbonate heavy oil reservoir. Cyclic steam injection with vertical wells completed with dual strings shows a production advantage over a similar vertical well completed with a single string in similar zones. At the same time, horizontal wells with multi-stage hydraulic fracturing stimulation offer marginal benefits. The risk of increased hydraulic stimulation costs could undermine the value created by horizontal drilling and completion.
Improved Amott Tests Help Quantify Primary Driving Forces in Spontaneous Imbibition in Water-Wet and Oil-Wet Limestone Rock
Authors: Kaprielova Ksenia , Yutkin Maxim , Gmira Ahmed , Ayirala Subhash , Yousef Ali , Radke Clayton , Patzek Tadeusz
Published: March 2023

The improved oil recovery techniques, such as customized ionic composition waterflood or "smart-water" flood, are being developed to increment crude oil production. Counter-current spontaneous imbibition of brine into oil-saturated rock is a critical mechanism of recovery of the crude oil bypassed in highly-heterogeneous carbonate rocks. In laboratory, spontaneous imbibition in the Amott cell experiment is the main instrument to explore oil recovery from oil-saturated core plugs at different wettability conditions. The classical Amott test, however, masks a number of flaws that hinder interpretation of the physical phenomena in recovery dynamics and precise modeling of the cumulative recovery profiles. In this work, we identify these flaws in the spontaneous imbibition experiments with mixed-wet limestone samples saturated with crude oil. We describe an improved Amott method and study crude oil recovery from mixed-wet carbonate core plugs. The introduced modifications of the Amott test ensure reliable and reproducible results for both non-wetting mineral and crude oils. Finally, we show that the resulted smooth recovery profiles of oil production can be described with a mathematical model with high accuracy. For the first time, we show that generalized extreme value (GEV) distribution can be applied to model cumulative oil production from mixed-wet carbonate core samples.
Counting the Effect of Crude Oils: Towards Increasing the Efficiency of Carbonate Matrix Acidizing
Authors: Al Hamad Mohammed , Abbad MustaphaFarhan , Ali Farhan , AlOtaibi Nader , AlRadhwan Azizah , AlQuisom Mohammed , Abdallah Wael
Published: March 2023

Carbonate matrix acidizing creates wormholes in the damaged formation around the wellbore and is used extensively to enhance well productivity. There are many factors discussed in literature that can positively or negatively affect the efficiency of carbonate matrix acidizing, such as mineralogy, permeability, porosity, and factors associated with the rock matrix and the acidizing fluids. However, the influence of reservoir crude oil on the acidizing operation has not been addressed and is the subject of this study.

Several limestone outcrop samples were selected and used in this study after evaluation of their petrophysical properties. The samples were fully saturated with deionized water; some samples were centrifuged and aged at high-pressure/high-temperature (HP/HT) conditions with different grades of crude oils. Linear acidizing experiments were executed; the preliminary acidizing tests showed optimal flow rate of 2 cm3/min. A baseline test was then conducted, using preflush fluid injection prior to acidizing to represent the real scenario of a stimulation job in the reservoir. The preflush helped to clean out the rock matrix, preparing the sample for acid injection. Lower pore volume before breakthrough (PVBT) was observed compared to the preliminary tests without the preflush. Then, linear acidizing tests were run on oil-saturated core samples. The results showed that the lower crude oil API is, the less acid volume needed to achieve acid breakthrough. This is mainly due to the viscous fingering that occurs because of the high viscosity contrast between the low-API crude oil and the 15% HCl acid used.

These results show the impact of crude oils with different API on the acidizing efficiency, which is very important information for reservoir engineers and should help proper planning the potential volume of acid needed and in making the right operational decisions for better financial impact.
Gas Tracer Technology to Improve Reservoir Understanding and Evaluate EOR Strategy, a Pilot Study in Kuwait
Authors: Al-Mayyan Haya , Pradhan Akshaya , Ziyab Khaled , Wurtz Marie , Huseby Olaf , Nurafza Peyman , Faulkner Tom
Published: March 2023

This paper describes planning, implementation, and results of chemical gas tracers used in a gas injection pilot study in a heterogeneous multilayer reservoir, onshore Kuwait. The use of tracer for waterflooding is a common practice to understand and improve field performances. In contrast, tracing injected gas with chemical tracers is applied less frequently. This study presents the first implementation of gas tracers in a pilot study in Kuwait and is an early adaptation of tracers to investigate gas-based EOR in the Middle East. The pilot comprises of one injector completed in three target layers and seven producers, completed in similar or other different layers. Unique gas tracers were injected into isolated layers independently at different times to evaluate the injector-producer connectivity in each layer. The producers and re-injected gas were sampled for one year to evaluate gas tracers return. The recovered tracer masses were evaluated against the injected amount to provide information on connectivity and sweep efficiency. The main revelation from the gas tracer study is their distinct difference from what could be expected from a consideration of the water flow itself. A likely explanation for the difference is that the water and gas behave differently in the reservoir, which in turn leads a conclusion that gas enhances the production of oil by replacing oil in the reservoir volumes.
CO2 Foamed Fracturing Fluids for High Temperature Hydraulic Fracturing
Authors: Karadkar Prasad , Harbi Bader , Malik Ataur , Alsakkaf Mohammed , Khan Safyan
Published: March 2023

CO2-foamed fracturing fluids injection can assist water conservation during hydraulic fracturing. Moreover, foamed fracturing fluids offer a desirable alternative over conventional fracturing fluids, particularly in stimulating water-sensitive formations, the need for shortened flowback time, and energizing created fracture geometry. The thermal stability of foam at high temperatures is one of the main challenges. In this paper, CO2-foamed acrylamide-based terpolymer based fracturing fluid was developed for high temperature application.

The foam viscosity development depends on the gas, foam quality, the viscosity of the external phase, foaming agent and foam stabilizers. Rheological properties of N2 and CO2 foams containing acrylamide-based terpolymer were measured at high temperatures i.e. 300 to 350°F and shear rate from 100 to 500 1/s. A circulating flow loop foam rheometer was used to measure the rheological behavior of foamed fluid prepared using linear gel. Foam stability improvement using nanoparticles was also demonstrated.

The viscous character of the external phase of the foam plays a considerable role in the viscosity of foam. In this paper, water and linear gel prepared using 35 ppt acrylamide-based terpolymer has been studied at 75% foam quality and two different temperatures. A 75% quality foam viscosity having water as the external phase gave 70 cp with N2and 31 cp with CO2 at 100 1/s, whereas viscus linear gel gave 146 cp with N2 and 64 cp with CO2 at 100 1/s studied at 300°F. After increasing the test temperature to 350°F, there was a significant drop in viscosity noticed. The thermal stability of foam can be enhanced by the synergetic effect of surfactant and nanoparticles. The foam half-life was delayed from 5.5 min to 9.1 min after the addition of silica nanoparticles using water as base fluid.

Viscous properties of the fracturing fluids influence the fracture geometry and capability of transporting proppant into the fracture. Based on available literature reports, the rheological properties of foamed fracturing fluids limit to 300°F. This paper reveals the rheological properties of CO2-foamed fracturing fluids in a temperature range of 300 to 350°F and therefore helps to design fracturing treatment to stimulate reservoirs with high temperatures.
Addressing Hydraulic Fracturing Performance Challenges in HPHT Well with New Fluid System and Comprehensive Fracturing Study Utilizing Full 3D Simulator
Authors: Nurlybayev Nurlan , Al-Jalal Ziad , Samuel Mathew , Farouk Mohammad , Ghazwi Mustafa , Yaseen Ali , Muhammad Raja Jalil
Published: March 2023

For achieving successful stimulation treatment in HPHT environment, a robust and state-of-the-art fluid technology together with the use of a versatile simulation design tool is crucial. The scope of this paper is to present case histories on the fracturing design, application and evaluation and its results in HTPT wells in Saudi Arabia. Additionally, a comparative analysis and recommendations will be presented to identify the optimum hydraulic fracturing treatment design for HPHT applications.

Extensive laboratory research was performed to develop and optimize a robust fracturing fluid that can be used for HT application in low permeability wells in Saudi Arabia, in the design phase of the program. Several chemically modified polymer fluid systems were developed, and their stability at high temperature, proppant suspension, and regained permeability were determined. Test phase was considered as a very critical stage to meet the project targets, as in either case indigent fluid rheology leads to ineffective stimulation treatments, especially in applications above 300 deg F. Upon completing the laboratory tests, the fracturing design was considered to apply full 3D software for achieving a comprehensive simulation of fracture model.

The laboratory research and development allowed the development of a new high temperature fracturing fluid that met the requirements, and provided stability for the required pumping time, to deliver low formation damage, manageable gel breaking time, excellent fracturing fluid leak-off control and sufficient proppant transport capabilities. Validation of fracturing fluid for field implementation was not enough, as sufficient fracturing design had to be in place, thus full 3D modelling software was used, utilizing essential well and formation information and detailed parameters of the new fluid system. A comprehensive study has been done during new fracturing fluid development phase, and additionally a comparison of pseudo 3D and full 3D software models for different scenarios were performed to optimize the fracture treatment design.

The paper will present precise solutions to perform fracturing treatment in HPHT formations and will be a guide for designing the treatment fluid system, fracture modelling and well treatment execution. Additionally, the advantages of using full 3D software for fracturing simulations and its correlation with field production results will be highlighted.
Reviving Production From Over 100 Deep Gas Wells Suffering From Halite Deposition In Oman Thru Velocity String
Authors: Al Rashdi Ahmed , Ghaempanah Babak , Al Hijri Amira , Koot Wouter , Bolourinejad Panteha , Al Daraai Thabit , Al Battashi Ibrahim , Awan Kamran
Published: March 2023

Following the reduction of system pressure through depletion compression more than 150 deep gas wells started struggling from halite deposition. Halite deposition in the completion restricted or blocked the production from the lower reservoir in these wells and reduced the total gas production of the field by about 40%. Meanwhile, many of the wells with halite deposition issue were also suffering from liquid loading and velocity strings were isntalled in them as the primary means of gas well deliquification. Many of these wells with velocity string showed no further halite deposition due to increase of the bottom hole pressure and reduction of the draw-down. Consequently, frequent freshwater bull heading or clean out with coiled tubing were no longer needed. This observation triggered the idea to create synergy between gas well deliquification and halite management through installation of velocty string. This synergy does not exist in every case, and this paper elaborates on identifying where it exists.
An Overview of Advanced Subsurface and Surface Measurements for CCUS Project
Authors: Al-Zayani Alia I , Patil Pramod D. , Al-Qasim Abdulaziz S. , Kokal Sunil L.
Published: March 2023

Monitoring and surveillance (M&S) is one of the key requisites for assessing the effectiveness and success of any CCS/CCUS projects. It will help understand, track, monitor, and predict the Injectant plume migration, flow paths, and breakthrough times. The M&S helps in quantifying sequestered injected gas and any inadvertent leakage. It provides a good understanding of the remaining oil saturation (ROS) and its distribution in the reservoir.

A comprehensive and advanced monitoring and surveillance (M&S) program was developed and is currently being deployed to address CCS/CCUS project objectives. The advanced M&S plan incorporates conventional, advanced, and emerging novel technologies for wellbore and inter-well measurements. These include advanced time-lapse pulsed neutron, resistivity, diffusion logs, and bore-hole gravity measurements, cross-well geophysical measurements, water and gas tracers, geochemical, compositional and soil gas analyses, and 4D seismic and surface gravity measurements.

Results from monitoring and surveillance technologies provide a better understanding of the reservoir dynamics within the subject area. The results can be used to refine the reservoir simulation model and fine tune its parameters. This paper reviews some proven best practices and draws examples from ongoing projects and related novel technologies being deployed. It will then look at the new horizon for M&S technologies for CCS and CCUS.
Rigless Mineralogy Logging- A Reality for Improved Evaluation of Complex Formations
Authors: Van Steene Marie , Ma Shouxiang , Ghadiry Sherif
Published: March 2023

A new slim pulsed neutron (nPN) logging technology has recently been introduced in the industry. Although the technology's main deliverables aim at reservoir saturation monitoring, the technology has seen substantial improvements in quantitative mineralogy logging. It is now capable of providing mineralogy data quality on par with openhole measurements, thus filling the gap where mineralogy data are required but not acquired during openhole logging. The main objective of this paper is to assess this nPN technology for formation mineralogy, with discussions of advantages, sensitivities, uncertainties, and limitations. Best practices in obtaining high-quality mineralogy data with this technology in open hole or cased hole wells, riglessly, are also recommended.

The primary application of pulsed neutron (PN) logs is for reservoir saturation monitoring, be it with time-domain capture data (sigma) or with energy-domain spectral data (carbon-oxygen). With the current slim PN technology, mineralogy derived from the capture spectroscopy (featuring direct measurement of the main elements of silicon Si, calcium Ca, sulfur S, iron Fe, and gadolinium Ga) has always been the last resort and has been used only if no other lithology information is available, because it suffers from low precision and the difficulty to evaluate elements like magnesium Mg in carbonate reservoirs.

With the new nPN, the quality of the mineralogy log has improved dramatically, making it equivalent to the mineralogy obtained with openhole logging. It benefits from the latest technological advancements, including high output minitron source, fast electronics, and new detector material with high spectral resolution. Methodologically, it combines information from both capture and inelastic spectroscopy to deliver more precisely the elements of Si, Ca, S, Fe, Gd and magnesium Mg, aluminum Al, titanium Ti, and potassium K. The combination of capture and inelastic spectroscopy confers an advantage in increasing the sensitivity to magnesium, which allows separating calcite from dolomite.

Results show that the rigless nPN mineralogy data quality is close to the latest and most advanced openhole spectral mineralogy log quality, complementing the lithology logs interpreted from traditional openhole logs. It allows for a more precise evaluation of the mineralogy in complex evaluation situations, where mineralogy data are required but were not acquired during openhole logging, such as those wells drilled before elemental mineralogy logs were available just two decades ago. As with any other technologies, nPN has limitations. Proper job planning, recommended in this study, is the key to ensure data quality.

New nPN provides an opportunity to gather reservoir mineralogy data in any wells, including rigless, in small holes, and through small restrictions, thereby filling the gap where mineralogy data is required, but not acquired during primary openhole logging.
Innovative Solid Lubricant Solution to Reduce Friction in Challenging ERD wells
Authors: Olivares Tulio , Turi Zach , Hayes Brandon
Published: March 2023

Extended reach drilling (ERD) has become increasingly more frequent in the petroleum industry as it allows access to additional reserves in oil and gas reservoirs from a single wellbore. Consequently, this has led to an increase in friction related problems while drilling and running casing. This paper describes the extensive lab testing and technical implementation of an innovative technology that utilizes a customized solid lubricant to reduce friction and help operators achieve challenging depths.

Comprehensive lab testing was conducted to tailor the required formulations of the solid lubricant and two field trials were completed to evaluate the performance. To properly conduct this evaluation, key performance indicators were established in both wells. A minimum torque reduction value of 10% was targeted for a treatment containing 5 pounds per barrel (ppb) of the solid lubricant. Baseline torque values were captured prior to the lubricant addition and were the benchmark for performance evaluation. Drilling fluid from the active pit was then enhanced with 5-ppb of the solid lubricant and sweeps were pumped downhole to reduce friction.

Two extended reach wells were identified in which water-based mud was used to drill. On Well A, at 79-degree inclination high and erratic torque was experienced which affected the drilling performance. Baseline torque was recorded and a sweep with 4 ppb of the solid lubricant was pumped: resulting in a 5.5% torque reduction. After drilling another stand, a second sweep was pumped with 5 ppb concentration and torque was reduced 14.7%. On Well B, at 84-degree inclination high and erratic torque was once again experienced. Baseline torque was recorded, and the first sweep was pumped with 5 ppb of the solid lubricant: resulting in a 10.4 % torque reduction. A second sweep was immediately pumped with another 5 ppb concentration and torque was reduced by 24.3%. In both Well A and Well B, a pill was spotted in the open hole with 8 ppb solid lubricant concentration to assist with the liner run. These field applications successfully demonstrated the concept of this innovative technology to reduce friction and overcome torque challenges in ERD applications; thus, resulting in a drastic reduction in nonproductive time.

The industry is continuously looking for opportunities to reduce non-productive time while drilling. This innovative solid lubricant is environmentally safe, compatible in all mud systems, and is highly effective in low concentrations to reduce friction while drilling in some of the most challenging extended reach wells. Minimizing friction and the subsequent torque issues will allow for optimal rates of penetration while drilling in these challenging conditions and thus reduce the overall time constructing the well.
Ranking of Geologic and Dynamic Model Uncertainties for Carbon Dioxide Storage in Saline Aquifers
Authors: Ates Harun , Gupta Anuj , Chandrasekar Vikram , Vaidya Ravimadhav , AlMajid Muhammad , Yousif Zuhair
Published: March 2023

Growing concerns over global climate change is also increasing the interest in developing technologies to reduce the concentration of carbon dioxide (CO2) in the atmosphere. Geological Carbon Sequestration which injects CO2 into subsurface formations such as deep saline aquifers, depleted hydrocarbon reservoirs are some of the viable options to reduce CO2 emissions into the atmosphere. Deep saline aquifers are a particularly good choice due to their wide geographical distribution and proximity to emission sources that provide easy accessibility and storability of CO2.

Saline aquifers, however, are data-poor systems that requires a thorough understanding of the impact of all factors and their uncertainties on long-term CO2 storage for risk assessment. This study considers a wide range of geologic and dynamic model uncertainties, including structural uncertainties, petrophysical heterogeneities, dynamic flow parameters and geochemical reactions to define the most critical parameters for different CO2 trapping mechanisms. Experimental design over stochastic modelling and sampling is used to minimize the computational cost of the study.

A commercially available, compositional reservoir simulator with reactive transport modeling capability has been used in this study to account for the impact of potential geochemical reactions. Assumed reactive transport model considers the water solubility, ionization, and mineral trapping mechanisms of CO2 in saline reservoirs for a range of components of dissolved salts in the brine as well as the pH of the brine. Chemical reactions that may occur with the rock minerals (Kaolinite, Anorthite and Calcite) when adding the CO2 are prescribed as input into the simulator. Simulations also include effects of hysteresis and diffusion processes.

Study shows that the most important parameter for all trapping mechanisms is the permeability since it controls the injection capacity. Beyond that, different combination of parameters with different range of uncertainties alter the ranking of factors influencing dissolution, ionization, hysteresis, mineralization and the movement of CO2 within the aquifer. There is no unique set of parameters that maximizes all storage mechanisms. There is a significant overlap and change in amount the amount of CO2 stored via different mechanisms depending on the parameter combinations. Study results also provide insights into how one can prioritize data gathering needs depending on the objectives, data uncertainties and their sensitivities for an aquifer site under consideration.
NGL Process Optimization at Khurais Producing Facility to Maximize NGL Recovery and Minimize H2S Content through HYSYS Simulations
Authors: Bajuaifer Hatem A. , Khan Ashiff , Hawsawi Ahmad M. , Amminudin Kamarul A.
Published: March 2023

This paper covers an optimization study at Aramco's Khurais processing facility to maximize NGL yield and minimize H2S content through HYSYS simulation. Model validation and identifying the confidence level of the model (prior optimization) approach and results are covered along with the realized results of the optimized operating envelope in simulation compared to field trial results.

The optimization approach focused on flashing more light ends due to a pressure drop in both the condensate feed drum and condensate stripper column while reducing NGL heating to maximize C3+ yield while maintain H2S below 30 PPMv. The identified optimized operating enveloped was implemented and benefits were realized.

The main conclusions and realized benefits of adjusting the operating parameters to the optimized operating envelope includes maximizing NGL recovery in the facility by more than 900 BPD while maintaining quality parameters within limits, reduced the steam consumption by more than 150,000 lb/day and creating more tolerance to process upsets and normal fluctuations.

The novelty of this paper is that it describes a process to define the confidence level of the model prior to commencing the optimization on a pre-existing model. In addition, it highlighted a simple approach to maximize C3+ recovery while minimizing H2S content and energy consumption, which creates room for optimization opportunities in any gas plant with no gas sweeting system.
Re-Defining Successful Use of Multiple Stage Fracturing Technology in Tight Gas Wells
Authors: Arshad Waheed , Hassan Zuhair
Published: March 2023

Horizontal drilling and completion advances in tight gas and shales have allowed access to significant new resources both in existing fields and new plays. Open hole multi-stage fracturing (MSF) technologies using ball operated sleeves and openhole packers have generally been effective in delivering high productivity wells, worldwide. Successful case histories treating tight shale gas with MSF completions abound in current literature, however, it is important to note that a majority of these case histories deal with reservoirs with high pressures. Often tight gas reservoirs are initially found to be over-pressured (higher than water gradient), but as with all depletion drive systems, the reservoir pressure depletes with the removal of fluids. Pressure depletion brings along with it its own set of challenges. The wells cease to have the ability to flow naturally to surface, liquid loading, and artificial lift are issues that come to the forefront. Conventional multi-stage stimulation that was seemingly fast and efficient in high pressure environment loses its appeal in sub-hydrostatic pressure wells. The time spent between each stimulation stage to the onset of well flowback becomes long and detrimental to the recovery of the well. The fracturing fluid lost to the formation can negatively alter the relative permeability of gas in the reservoir and the longer the time spent to recover the fluids the damage tends to get irreversible. Quick and efficient clean-up of fracturing fluid is indispensable to maintain a well's productivity in tight, low pressure gas reservoirs.

A new generation of multi-stage completion systems is discussed in this paper. These multiple stage tools are operated by a single ball that opens several of the treating sleeves in one run thus allowing a large section of the reservoir to be treated simultaneously. The stimulation fluid placement is enhanced by pumping through limited entry ports of the stimulation sleeves at optimum injection rates supported by modern particulate diverting agents, and energized fluids. The operation time between the first stimulation (acid) stage hitting the formation to the well being flowed back can be cut down to a matter of few hours from an otherwise operation of a few days.

The results from this step change in completion and stimulation design have been spectacular providing several folds of productivity improvement. This application provides a fundamentally sound solution for treating low pressure, tight reservoirs.
Integrated Workflow of Acid Stimulation Evaluation and Selection for Productivity Enhancement in Carbonate Rocks
Authors: Sarsekov Arlen , Abed Abdalla , El Gohari Mohamed , Ryan Abraham , Kamaletdinov Bulat , Mahmoud Wael , Arali Vaishak , Enkababian Philippe
Published: March 2023

Most oil fields worldwide are stored in carbonate rocks, which vary in rock and fluid properties. Heterogeneity, thickness, and depth play vital roles in the selection of specific acid stimulation to improve the productivity and injectivity of the wells from near-wellbore damaged formation resulting from overbalance drilling. This paper describes the integrated workflow that guides petroleum engineers in the selection of optimum acid stimulation techniques and technologies for a specific field.

Specifically, this work discusses the stimulation strategies in the form of a stimulation workflow that considers various aspects to achieve the stimulation objectives. The stimulation objectives are also streamlined for the well objectives, which mainly consider the well completion approach. Considering the well completion and well objective, the stimulation strategies highlight the conveyance selections, fluid selections, and the methodologies. Guidelines are provided as examples for fluid specification. Some comparisons of the stimulation fluids are also shown to consider the advantages and disadvantages of each application. Example simulation and case studies show various applications in UAE.

Numerous new technologies and different acid types have been tested worldwide on different carbonate rocks whereas very limited information exists on a tailored acid stimulation workflow that can be fit to the needs of a specific field. The developed workflow is an integrated holistic guidance based on worldwide best practice of acid stimulation and can facilitate and guide technical expertise for production and cost optimization in different oil and gas fields. The latest stimulation technologies are highlighted for the reference on the case studies.
A Hybrid H2S Removal Solution. Using Liquid vs. Fixed Bed H2S Scavengers in Harmony
Authors: Crawshaw Michael , Brundick William , Juncker Michael , Barbuto Kristina , Jenkins Alyn , Lim Sooi Kim
Published: March 2023

Hydrogen Sulfide (H2S) is an organic compound created naturally during the decaying process. In crude oil and natural gas H2S is generated when Sulfur is removed from petroleum products. This phenomenon occurs at various stages during exploration, production and refining. In addition to the naturally occurring H2S, sulfate reducing bacteria or SRB produce Hydrogen Sulfide (H2S) souring the reservoir production. SRB’s are living organisms that require a specific set of circumstances to grow; they need organic carbon, a sulfur source, water and the correct temperature to produce H2S.

Some facilities may not have a desulfurization plan especially when the reservoir was initially identified as a ‘sweet well’. In this case desulfurization treatment was not considered in their operations and maintenance strategies. However, over recent years the enquiries for desulfurization on brown field operations have increased indicating that ‘sweet wells’ may or have turned sour, possibly due to introduction of SRB from the surface via water injection.
Exploration of Novel Sacrificial Fluids for Asphaltene Adsorption Remediation
Authors: Mohammed Isah , AlShehri Dhafer , Mohamed Mahmoud , Mohammed Kamal Shahzad , Olalekan Saheed Alade , Abdullah Sultan , Patil Shirish
Published: March 2023

One of the most extensively studied flow assurance issues in the petroleum industry is the precipitation and deposition of asphaltene. This is in part because of the molecular structure's intricacy and the interconnected elements that influence and regulate its activity. The injection of inhibitors and dispersants, which affect the economics of crude oil production, is now the most successful tactic used. Anywhere throughout the crude oil supply chain, from the reservoir through the tubing and refinery systems, there is an asphaltene concern. However, the area closest to the wellbore, where the greatest pressure decrease is seen, is the most prone to asphaltene adsorption and deposition. Thus, the goal of this study is to investigate how new sacrificial fluids might be used to reduce asphaltene adsorption and deposition around the wellbore. To prevent asphaltene from interacting with the rock surface and shifting the asphaltene problem into the tubing where its impact on wettability is low, the sacrificial fluid/rock ion-specific interactions are investigated.

This is a groundbreaking attempt to relocate the asphaltene issue from the wellbore into the tubing, where it does not affect the reservoir's wettability. The performance test (adsorption inhibitive capacity), binding energy analysis, adsorption experiments (adsorption affinity, configuration, and mechanism), and fluid characterization (salinity tolerance, surface energy, interfacial tension) of the chosen novel fluids for asphaltene adsorption mitigation are presented. The investigation of ion-specific rock-fluid interactions offers great potential in the search for an effective answer to the asphaltene problem, according to the results. This is proven by the fluids’ levels of binding energy to carbonate rock samples and their capacity to prevent interactions between asphaltene molecules and the rock surface. These studies’ findings open a fresh perspective into the creation of an economical strategy to deal with asphaltene issues and their effects. This study is the first to investigate a long-term fix for wettability changes brought on by asphaltene adsorption on the mineral rock. This entails looking for a fluid that, when used as a remediation fluid in cases of asphaltene deposition, has a stronger affinity for the rock than asphaltene and has the potential to remove asphaltene. Additionally, for the first time in the state of the art of remediation fluid design, realistic environmental conditions are considered in the search for this fluid.
Selection and Optimization of Demulsifier Based on Physio-Chemical Characteristics of Emulsion
Authors: Altowilib Ali , Gajbhiye Rahul , Mahmoud Mohamed , Solling Theis
Published: March 2023

The presence of crude oil/water emulsions is a burden in the petroleum industry. It leads to several operational and economic issues related to crude production, transportation, and refining processes. The stability of the emulsified oil is affected by water content, presence of organic/inorganic materials, formation brine salinity, and temperature. In reservoir fluid studies, applying chemical demulsifiers on emulsion samples is common to break the emulsion and reduce the water content to an acceptable level (less than 1 wt. %) to generate representative fluid composition results. However, this process depends heavily on the crude and the water compositions and the type of demulsifier used. An incompatible choice of demulsifier could strengthen the emulsion's stability or alter the fluid composition. This introduces the need to understand specific physiochemical properties to identify the root causes of demulsifier ineffectiveness.

In this study, two demulsifiers containing different functional groups (Type 1 and Type 2) were evaluated for their emulsion breakage ability. Nine oil samples from various fields were mixed with formation water in the first round and seawater in the second. The water-oil ratio of 80:20 was achieved using a blender for 1.5 minutes at 300 RPM. Saturates, Aromatics, Resins, and Asphaltene (SARA), viscosity, density, and sulfur content were determined for all oil samples. Furthermore, chemical analysis was conducted on all water samples to determine Total Dissolved Solids (TDS). After applying both demulsifiers at the same concentration (1% of total volume), separated water volumes were measured at 5, 10, 15, and 20 minutes and used to calculate the emulsion separation index (ESI). Results of this work showed that Type 1 demulsifier performed better than Type 2 in the formation water and seawater and while using different oils due to the resistance of the non-ionic surfactant to salinity, polarity, and water hardness. This study shows a methodology for effectively determining the optimum chemical demulsifier type to break emulsions by adequately understanding the chemistry of the oil, brine, resulting emulsions, and demulsifiers used.
New Generation Downhole Sand Detection Technology Leading to Confident Reservoir Sand Management and Cost-Effective Remedial Opportunities
Authors: Kurma Ravi , Al-Fadhli Wuroud M Kh , Ayyad Hazim , Mehraj Majid , Alajmi Abdulaziz
Published: March 2023

It has always been a challenge to accurately detect downhole sand producing zones. Older generation acoustic based sand detecting technologies were subject to error due to background noise related to the fluid production. Due to the common false detections with the legacy measurements, remedial workover plans were compromised (Adil, 2020)

A new technology that can differentiate between sand production and background fluid related noise has been developed. This technology can quantify the sand grain count through a piezo-electric sensor.

In this paper, a unique comprehensive study was conducted across a sector of the Greater Burgan field to better understand the variables contributing to sand production through integrating the static model along with the dynamic production profile which included the new, state-of-art downhole sand detection technology.

Based on the results, a guideline was formulated to predict the future sand producing wells. This helps to proactively anticipate and therefore, better manage the sand production challenges.

This paper covers the results of nine wells logged across the same reservoir units. The main objective was to identify and quantify the sand producing intervals. The secondary objective was to determine the water producing zones. Wireline production log were combined with this new technology in all the wells to obtain the fluid production intervals along with the sand producing zones at the same conditions in the same run. Along with the spinner, water hold up probes pinpointed the water entries. The sand impact detection tool provided the fourth phase, sand, with excellent repeatability. Multiple rates were conducted in some of the wells to determine the critical drawdown pressure at which sand production occurs.
Demulsification of Heavy Crude Oil Emulsion Driven by Natural Materials
Authors: Adewunmi Ahmad A. , Kamal Muhammad Shahzad , Gbadamosi Afeez , Patil Shirish
Published: March 2023

This study investigated the effectiveness of fly ash (FA) and extracted silica (SC) from sand as natural demulsifiers for breaking stable crude oil emulsions and spiltting oil-water into phases. A series of stable emulsion was formulated and the oil-water ratio was 4:6. Various concentrations of either FA or SC ranging from 0.25 – 1% were added into vials containing the prepared emulsions and demulsification test was conducted inside the oven at 70 °C. Rheology and interfacial tension characterizations were used to illustrate the demulsification mechanism of FA and SC demulsifiers. According to the experimental outcomes, the demulsification from the bottle test showed that water removal increased with the increasing FA concentration. The demulsification efficiency (DE) of 0.25, 0.5, 0.75, and 1% FA was 35.33%, 81.99%, 92.67% and 93.77%, respectively; within 150 minutes of demulsification duration while all the tested SC concentrations (0.25, 0.5, 0.75 and 1%) achived 90.11%, 93.87%, 95.89%, and 95.89%, respectively; under the same demulsification period. The reference sample (blank) only achieved DE of 14.76%. Rheological characterization showed that the incorporation of either FA or SC caused the reduction of emulsion viscosity which indicated the breaking of emulsion and separation of oil and water. The results from the interfacial tension measurments revealed that FA and SC could migrate and adsorb at oil-water interface. The addition of either FA or SC in the oil-water system led to a more drastic reduction in the interfacial tension as compared to the interfacial tension of oil-water system devoided of the FA and SC. The interfacial tensions of oil/water system in the presence of 0.25% and 1% FA were 18.91 mN/m and 14.85 mN/m, respectively, and that of 0.25% and 1% SC were 16.44 mN/m and 14.80 mN/m, respectively, after 200 seconds and that of blank sample was recorded to be 18.1 mN/m in the same duration.