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Abbas, Ahmed K. (Iraqi Drilling Company, Missouri University of Science and Technology) | Alhameedi, Hayder A. (University of Al-Qadisiyah, Missouri University of Science and Technology) | Alsaba, Mortadha (Australian College of Kuwait) | Al Dushaishi, Mohammed F. (Oklahoma State University) | Flori, Ralph (Missouri University of Science and Technology)
Coiled tubing (CT) technology has been widely used in oilfield operations, including workover applications. This technology has achieved considerable economic benefits; however, it also raises new challenges. One of the main challenges that were encountered while using this technology is the buckling of the CT string. It can occur when the axial compressive load acting on the CT string exceeds the critical buckling loads, especially in highly deviated/horizontal and extended reach wells. Moreover, this issue becomes more critical when using non-Newtonian fluids. Therefore, the major focus of this study is to identify the frictional pressure loss of non-Newtonian fluids in an annulus with a buckled inner tubing string.
In the present study, a laboratory-scale flow loop was used to investigate the influence of various buckling configurations (i.e., sinusoidal, transitional, and helically) of the inner pipe on the annular frictional pressure losses while circulating non-Newtonian drilling fluids. The experiments were conducted on a horizontal well setup with a non-rotating buckled inner pipe string, considering the impact of steady-state isothermal of laminar, transition, and turbulent flow regions on frictional pressure losses. Six different Herschel-Bulkley fluids were utilized to examine the dependence of pressure losses on fluid rheological properties (i.e., yield stress, consistency index, and flow behavior index).
Experiments showed potential to significantly decrease the frictional pressure losses as the axial compressive load acting on the inner pipe increases. The effect of buckling was more pronounced when fluids with higher yield stress and higher shear-thinning ability were used. In addition, by comparing the non-compressed and the compressed inner pipe, an additional reduction in frictional pressure losses occurred as the axial compressive load increased. However, the effect of the compressed inner pipe was insignificant for fluids with a low yield stress, consistency index, and high-flow-behavior index, especially in the laminar region. The information obtained from this study will contribute toward providing a more comprehensive and meaningful interpretation of fluid flow in the vicinity of a buckled coiled tubing string. In the same manner, accurate knowledge of the predicted friction pressure will improve safety and enhance the optimization of coiled tubing operations.
Al-Saedi, Hasan N. (Missouri University of Science and Technology/ Missan Oil Company) | Qubian, Ali (Kuwait Oil Company) | Al-Bazzaz, Waleed (Kuwait Institute for Scientific Research) | Flori, Ralph (Missouri University of Science and Technology)
Low salinity (LS) water flooding in the sandstone reservoir is of pronounced interest of the prospective for improved oil recovery. In this study, laboratory experiments in low-permeable sandstone core plugs saturated with various crude oil containing different acid numbers were presented. Several low-permeable sandstone cores (1-3 mD) were taken from Bartlesville Sandstone Reservoir from Eastern Kansas were successively flooded with seawater and different LS water. The reservoir cores were cleaned and saturated with formation water (FW) and then aged in three kinds of crude oil (different acid numbers) for six weeks at 90 C. To evaluate LS water in the low-permeable reservoir core plugs, core flooding tests were performed. Contact angle and spontaneous imbibition tests were also carried out. The results obtained from LS water flooding showed that an improvement in oil recovery up to 12% of the original oil in place when the acid number (AN) and core permeability were low. The water wetness, and in turn, the oil recovery reduced with increased crude oil's AN and as the permeability increased. The contact angle and spontaneous imbibition tests confirmed the appropriate wettability change is attainable with LS water flooding. The results were deliberated in relation to wettability change processes by LS Water.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Belhaij, Azmi (Saudi Metal Coating Company) | Alkamil, Ethar H. K. (University of Basrah)
Nowadays, as the worldwide consumption of hydrocarbon increases, while the conventional resources beings depleted, turning point toward unconventional reservoirs is crucial to producing more additional oil and gas from their massive reserves of hydrocarbon. As a result, exploration and operation companies gain attention recently for the investment in unconventional plays, such as shale and tight formations. A recent study by the U.S. Energy Information Administration (EIA) reported that the Middle East (ME) and North Africa (NF) region holds an enormous volume of recoverable oil and gas from unconventional resources. However, the evaluation process is at the early stage, and detailed information is still confidential with a limitation of the publication in terms of unconventional reservoirs potential. The objective of this research is to provide more information and build a comprehensive review of unconventional resources to bring the shale revolution to the ME and NF region. In addition, new opportunities, challenges, and risks will be introduced based on transferring acquiring experiences and technologies that have been applied in North American shale plays to similar formations in the ME and NF region. The workflow begins with reviewing and summarizing more than 100 conference papers, journal papers, and technical reports to gather detailed data on the geological description, reservoir characterization, geomechanical property, and operation history. Furthermore, simulation works, experimental studies, and pilot tests in the United States shale plays are used to build a database using the statistic approach to summarize and identify the range of parameters. The results are compared to similar unconventional plays in the region to establish guidelines for the exploration, development, and operation processes. This paper highlights the potential opportunities to access the unlocked formations in the region that holds substantial hydrocarbon resources.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Flori, Ralph (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Noles, Jerry (Coil Chem LLC) | Essman, Jacob (Coil Chem LLC) | Kim, Sangjoon (Coil Chem LLC) | Alkamil, Ethar H. K. (University of Basrah)
Hydraulic fracturing operation requires securing sufficient water resources to access unlocked formations. Successful treatment depends on the fracture fluids that mainly consists of water-based fluid with a low percentage of chemical additives around 1%. Therefore, the oil and gas industry are considered as the largest freshwater consumers by 3 to 6 million gallons of water per well based on a number of fracturing stages. As a result, the traditional water resources from subsurface and surface are getting depleted, and availability of freshwater is becoming more difficult with high cost due to continued demand. For example, operator companies in West Texas face many challenges, including a recent increase from USD 3 to 10 per m3 of freshwater. In addition, transporting process of the raw water to the fracture sites, such as Bakken has an environmental impact, and expensive costs up to USD 5/bbl, while costs of water disposal in range of USD 9/bbl.
This paper aims to study the produced water as alternative water-based fluid with high viscosity friction reducers (HVFR) to reduce environmental footprints and economic costs. To address utilizing produced water as an alternative capable water resource that may use during fracturing treatment, this research presents an experimental investigation associated with using the Permian high-TDS brine water with HVFRs. This work includes experimental research, case studies, and guidelines work on recent improvements on using HVFR to carry proppant and capture the optimum design in fracturing operations. Moreover, the research conducted scaled lab friction measurements that can in turn to be used to improve forecasting of frictions in the field, and therefore of expected surface treating pressures during fracture treatments. Evaluating pipe friction as a function of time to compare HVFRs efficacy in lab and field conditions as well as to predict maximum injection rate during a frac job is investigated.
The outcomes show that high-TDS Permian water with highest dosage of HVFRs had instantaneous pressure reduction effect in 10 seconds while low dosage of HVFRs had lost the effect slowly after 4 min. 30 sec. Also, the results of this study show that the variation of viscosity and pressure reduction at higher shear rate is small. The warm temperature helped rapid polymer dispersion and provided better environment to polymer hydration leads to rapid pressure reduction. Finally, successful implementation in Wlofcamp formation shows that the operation treating pressure reduced from 11,000 to 8,000 psi. The general guidelines obtained can promote the sustainability of using hydraulic fracturing treatment to produce more oil and gas from unconventional resources without considering environmental issues.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Noles, Jerry (Coil Chem LLC) | Kim, Sangjoon (Coil Chem LLC)
The success of hydraulic fracture treatment can be evaluated by measuring fracture conductivity and regained permeability. However, selecting the suitable fracture fluid system plays an essential role to minimize or eliminate the formation damage. To address the potential formation damage during fracturing treatment, this research presents a comprehensive review of a good number of published papers that are carefully reviewed and summarized including experimental research, case studies, and simulation work on recent improvements of using HVFR to carry the proppant and capture the optimum design in fracturing operations. This paper also provides formation damage mechanisms such as chemical, mechanical, biological, and thermal. Moreover, the research explains the fracture damage categories including damage inside fracture and damage inside the reservoir. The advantages of using HVFRs are also fully explained. Experimental rheological characterization was studied to investigate the viscoelastic property of HVFRs on proppant transport. The successful implication of utilizing HVFRs in the Wolfcamp formation, Permian Basin was discussed.
The findings of this research are analyzed to reach conclusions on how HVFRs can be an alternative fracture fluid system of many unconventional reservoirs. Comparing to the traditional hydraulic fracture fluids system, the research shows the many potential advantages that HVFR fluids offer, including superior proppant transport capability, almost 100% retained conductivity, around 30% cost reduction, and logistics, such as minimizing chemicals usage by 50% and operation equipment on location, reduce water consumption by 30%, and environmental benefits. Finally, this comprehensive review addresses up-to-date challenges and emphasizes necessities for using high viscosity friction reducers as alternative fracture fluids.
Abbas, Ahmed K. (Iraqi Drilling Company) | Flori, Ralph (Missouri University of Science and Technology) | Almubarak, Haidar (Missouri University of Science and Technology) | Dawood, Jawad (Basra Oil Company) | Abbas, Hayder (Missan Oil Company) | Alsaedi, Ahmed (Missouri University of Science and Technology)
Stuck pipe is still a major operational challenge that imposes a significant amount of downtime and associated costs to petroleum and gas exploration operations. The possibility of freeing stuck pipe depends on response time and subsequent surface action taken by the driller during and after the sticking is experienced. A late and improper reaction not only causes a loss of time in trying to release stuck pipe but also results in the loss of an important portion of expensive tubular, downhole equipment and tools. Therefore, a fast and effective response should be made to release the stuck pipe. Investigating previous successful responses that have solved stuck pipe issues makes it possible to predict and adopt the proper treatments. This paper presents a study on the application of machine learning methodologies to develop an expert system that can be used as a reference guide for the drilling engineer to make intelligent decisions and reduce the lost time for each stuck pipe event.
Field datasets, including the drilling operation parameters, formation type, and fluid mud characteristics, were collected from 385 wells drilled in Southern Iraq from different fields. The new models were developed to predict the stuck pipe solution for vertical and deviated wells using artificial neural networks (ANNs) and a support vector machine (SVM). The results of the analysis have revealed that both ANNs and SVM approaches can be of great use, with the SVM results being more promising. These machine learning methods offer insights that could improve response time and strategies for treating stuck pipe.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Noles, Jerry (Coil Chem LLC) | Kim, Sangjoon (Coil Chem LLC)
Viscoelastic property of high-viscosity friction reducers (HVFRs) was developed as an alternative fracturing fluid system because of advantages such as the ability to transport particles, higher fracture conductivity, and potential lower cost due to fewer chemicals and equipment on location. However, concerns remain about using HVFRs to transport proppant in DI water and harsh brine solution (e.g. 2wt% KCl and 10 lbs. brine). The primary objective of this study is to investigate the viscoelastic property that can help to understand the true proppant transporting capacity of fracturing fluids in high-TDS environment.
To address the evaluation performance of HVFRs, a comprehensive review of numerous papers associated to viscoelastic property of hydraulic fracturing fluids were investigated and summarized. This paper also provides a full comparison study of viscosity and elastic modulus between HVFRs and among fracturing fluids such as xanthan, polyacrylamide-based emulsion polymer, and guar. Moreover, viscosity profiles and elastic modulus were conducted at different temperatures. Better proppant transportation effect though higher viscosity through Stoke's law and the effect on proppant transportation from elastic modulus comparison were also investigated. Finally, HVFR Conductivity test and successful field test result were explained.
The results of the experimental work show that viscoelastic property HVFRs provides good behavior to transport proppant. Viscosity profile decreased slightly as the temperature increased from 75 to 150 when the DI water was used. While using 10 lbs. Brine the viscosity was reduced by 33%. The longer polymer chains of HVFR indicated better elastic modulus in DI water. The elastic modulus also indicated that the highest values at frequency 4.5 Hz from each amplitude, and lower values as amplitude was increased. Although high molecular weight HVFRs were utilized on the conductivity test, the results observed that the regained permeability was up to 110%. Finally, the promising results from the case study showed that using HVFRs could be performed economically and efficiently for the purpose of proppant transportation and pressure reduction in high TDS fluids.
High-viscosity friction reducers (HVFRs) have been gaining popularity and increase in use as hydraulic fracturing fluids because HVFRs exhibit numerous advantages such as their ability to carry particles, their promotion of higher fracture conductivity, and their potentially lower cost due to fewer chemicals and equipment on location. However, concerns remain about using HVFRs with produced water containing a high level of TDS (Total Dissolved Solids). This study investigates the influence of the use of produced water on the rheological behavior of HVFRs compared to a traditional linear guar gel. This work also aims to correlate proppant settling velocity behavior with rheological properties of HVFRs vs. linear gel on hydraulic fracturing operations. Comprehensive rheological tests of different HVFRs compared with linear gel were performed including, shear-viscosity and dynamic oscillatory-shear measurements using an advanced rheometer.
The results of these rheological measurements reveal that these polyacrylamide-based HVFR systems achieve a high viscosity profile in fresh water with associated high proppant-carrying capacity. On the other hand, increasing water salinity lowers HVFR’s viscosity, increases proppant settling velocity, and lessens the fluid’s proppant-carrying efficiency. Although in fresh water linear gel showed similar viscosity measurements with HVFR-A, the HVFR-A recorded a lower proppant settling rate because HVFR-A has a higher relaxation time (15.3 s) than the relaxation time of linear gel (1.73 s).
As expected, in high-TDS produced water the relaxation time and elastic behavior decreased for all the fracturing fluids tested. HVFR-B recorded the smallest reduction in relaxation time (about 14%) when tested in produced water vs. fresh water, and the resulting settling velocity increased by 29% from 3.4 cm/s to 4.85 cm/s. For linear gel, its reduction in relaxation time exceeded of 70% when changing water salinity from fresh water to high-TDS brine water. This high reduction of relaxation time leads to over 40% increase in proppant settling velocity from 5.3 cm/s to 8.7 cm/s in fresh water and produced water, respectively. This study confirms that HVFR’s elasticity (vs. it viscosity) properties enable successful proppant transport for a wide range of shear rates while viscosity (vs. elasticity) properties controls proppant settling velocity in linear guar-based fluids. This paper will provide greater understanding of the importance of complete viscoelastic characterization of the HVFRs. The findings provide an in-depth understanding of the behavior of HVFRs under high-TDS brine, which could be used as guidance for developing fracturing fluids and for fracture engineers to design and select better friction reducers.
Geri, Mohammed Ba (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Ofori, Bruce (Missouri University of Science and Technology) | Flori, Ralph (Missouri University of Science and Technology) | Sherif, Huosameddin (Missouri University of Science and Technology)
Recent studies have presented successful case studies of using HVFR fluids in the field. Reported cost reductions from using fewer chemicals and less equipment on the relatively small Marcellus pads when replacing linear gel fluid systems by HVFR. The investigation provided a screening guideline of utilizing HVFRs in terms of its viscosity and concentration. The study notes that in field application the average concentration of HVFRs is 2.75 gpt (gal per 1,000 gal)
Three different scenarios were selected to study fluid type effect using 3D pseudo simulator; as a first scenario; fracture dimensions as a second scenario; the last scenario was proppant type. The first scenario consists of two cases: utilizing HVFR-B as new fracture fluid in 20% of produced water was investigated in scenario I (base case). Comparison between HVFR and linear gel in the Middle Bakken was investigated in Case II of the first scenario. At the second scenario, fracture half-length was studied. Proppant distribution impact by using HVFR in Bakken formation was analyzed as the third scenario. The final scenario investigated the pumping flow rate influence on proppant transport of using HVFR. The concentration of HVFR-B was 3 gpt and the proppant size was 30/50 mesh. The treatment schedule of this project consists of six stages. The proppant concentration was increased gradually from 0.5 ppt to 6 ppt at the later stage.
In the case of using HVFR-B the fracture half-length was approximately 1300 ft while using linear gel created smaller fracture half-length. In contrast, using linear gel makes the fracture growth increase rapidly up to 290 ft as showed. To conclude, using HVFR-B created high fracture length with less fracture height than linear gel. Additionally, in using HVFR-B, the average fracture height was approximately 205 ft while using linear gel created increasing of the fracture growth rapidly up to 360 ft which represent around 43% increasing of the fracture height. In studying the impact of fracture half-length on proppant transport, increasing fracture half-length from 250 ft to 750 ft leads to the fracture growth rapidly up to 205 ft
Studying the impact of proppant size effect on proppant transport, we observed changing fracture conductivity across fracture half-length. Thus, the fracture height increasing with decreasing proppant mesh size. Fracture height increased from 193 ft to 206 ft by changing proppant mesh size from 20/40 to 40/70 mesh. With flow rate impact on proppant transport, it was observed that, the fracture height increases by increasing the pump rate. Utilizing HVFR-B in the fracture treatment provides higher absolute open flow rate (AOF) which is around 2000 BPD. On the other hand, the outcomes of using linear gel has less AOF that about 1600 BPD. Also, Increasing the Xf and proppant mesh size leads to increase the AOF.
This project describes comparison of the successful implementation of utilizing HVFR as an alternative fracturing system to linear gel.
The primary purpose of using traditional friction reducers in stimulation treatments is to overcome the tubular drag while pumping at high flow rates. Hydraulic fracturing is the main technology used to produce hydrocarbon from extremely low permeability rock. Even though slickwater (water fracturing with few chemical additives) used to be one of the most common fracturing fluids, several concerns are still associated with its use, including usage of freshwater, high-cost operation, and environmental issues. Therefore, current practice in hydraulic fracturing is to use alternative fluid systems that are cost effective and have less environmental impact, such as fluids which utilize high viscosity friction reducers (HVFRs), which typically are high molecular weight polyacrylamides. This paper carefully reviews and summarizes over 40 published papers, including experimental work, field case studies, and simulation work. This work summarizes the most recent improvements of using HVFR’s, including capability of carrying proppant, reducing water and chemical requirements, its compatibility with produced water, and environmental benefits in hydraulic fracturing treatments. A further goal is to gain insight into the effective design of HVFR based fluid systems.
The findings of this study are analyzed from over 26 field case studies of many unconventional reservoirs. In comparing to the traditional hydraulic fracture fluids system, the paper summaries many potential advantages offered by HVFR fluids, including: superior proppant transport capability, almost 100% retained conductivity, cost reduction, minimizing chemicals usage by 50%, less operating equipment on location, reducing water consumption by 30%, and fewer environmental concerns. The study also reported that the common HVFR concentration used was 4gpt. HVFRs were used in the field at temperature ranges from 120°F to 340°F. Finally, this work addresses up-to-date challenges and emphasizes necessities for using high viscosity friction reducers as alternative fracture fluids.