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.
Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Alkinani, Husam H. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Alashwak, Nawaf A. (Missouri University of Science and Technology) | Alshammari, Abdullah F. (Missouri University of Science and Technology) | Alkhamis, Mohammed M. (Missouri University of Science and Technology) | Mutar, Rusul A. (Ministry of Communications and Technology)
Drilling wastes generated in large volumes is recognized to have many effects on the environment. Several techniques have been applied by the oil and gas industry to overcome the impacts of drilling waste on the environment, an example of these techniques is using environmental friendly drilling fluid additives.
This work investigates the potential of using White Sunflower Seeds’ Shell Powder (WSSSP) as an environmental friendly drilling fluid additive. This material was prepared in-house. Experimental evaluation has been carried out to investigate the ability of WSSSP to enhance several properties of water-based drilling fluid under two different pH conditions. The WSSSP was first evaluated at 9.3 pH then the pH was increased using sodium hydroxide to 11.5. Several properties of drilling fluid were measured. The measurements included testing the rheological properties using viscometer, measuring the filtration using standard low-pressure low-temperature filter press, the pH using pH tester, and other important properties.
The findings of this work showed that WSSSP in 9.3 pH environment reduced the fluid loss by 18% and 30% when 1% and 2% concentrations of WSSSP were added, respectively. This reduction in fluid loss was along with forming a thin filter cake. The filter cake thickness of the reference fluid was decreased from 3 mm to 2.14 mm and 1.9 mm at 1% and 2% concentrations of WSSSP. Additionally, WSSSP resulted in increasing the plastic viscosity (PV) compared to the reference fluid by 33.33% at 1% and 2% concentrations. While the yield point (YP) was increased by 22.22% and 44.44% when 1% and 2% concentrations of WSSSP were added, respectively. Both the initial and final gel strengths were increased by 27.27%, 44.44 %, 7.14% and 14.28% at 1% and 2% concentrations, respectively. Moreover, the results in 11.5 pH emphasized the efficient performance of WSSSP, and it showed better improvement in the filtration specifications and the rheological properties. In other words, PV, YP, and gel strength were significantly increased; while the fluid loss was very low and the filter cake was very thin at 11.5 pH condition compared to 9.3 pH condition for the same concentrations, proving the ability of WSSSP to perform better under higher pH condition.
The significant enhancement in the rheological and filtration properties, suggesting the applicability of using this additive as a rheology modifier and filtration control agent. These results showed the potential use of WSSSP as an alternative for some of the toxic materials used today in the oil and gas industry. This work demonstrates that this additive will help to reduce both the impact on the environment along with reducing the cost of drilling fluid and drilling waste handling.
Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Alkhamis, Mohammed M. (Missouri University of Science and Technology) | Mutar, Rusul A. (Ministry of Communications and Technology)
Lost circulation is a complicated problem to be predicted with conventional statistical tools. As the drilling environment is getting more complicated nowadays, more advanced techniques such as artificial neural networks (ANNs) are required to help to estimate mud losses prior to drilling. The aim of this work is to estimate mud losses for induced fractures formations prior to drilling to assist the drilling personnel in preparing remedies for this problem prior to entering the losses zone. Once the severity of losses is known, the key drilling parameters can be adjusted to avoid or at least mitigate losses as a proactive approach.
Lost circulation data were extracted from over 1500 wells drilled worldwide. The data were divided into three sets; training, validation, and testing datasets. 60% of the data are used for training, 20% for validation, and 20% for testing. Any ANN consists of the following layers, the input layer, hidden layer(s), and the output layer. A determination of the optimum number of hidden layers and the number of neurons in each hidden layer is required to have the best estimation, this is done using the mean square of error (MSE). A supervised ANNs was created for induced fractures formations. A decision was made to have one hidden layer in the network with ten neurons in the hidden layer. Since there are many training algorithms to choose from, it was necessary to choose the best algorithm for this specific data set. Ten different training algorithms were tested, the Levenberg-Marquardt (LM) algorithm was chosen since it gave the lowest MSE and it had the highest R-squared. The final results showed that the supervised ANN has the ability to predict lost circulation with an overall R-squared of 0.925 for induced fractures formations. This is a very good estimation that will help the drilling personnel prepare remedies before entering the losses zone as well as adjusting the key drilling parameters to avoid or at least mitigate losses as a proactive approach. This ANN can be used globally for any induced fractures formations that are suffering from the lost circulation problem to estimate mud losses.
As the demand for energy increases, the drilling process is becoming more challenging. Thus, more advanced tools such as ANNs are required to better tackle these problems. The ANN built in this paper can be adapted to commercial software that predicts lost circulation for any induced fractures formations globally.
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.
Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Alkinani, Husam H. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Amer, Ahmed S. (Newpark Technology Center/ Newpark Drilling Fluids)
Equivalent circulation density (ECD) management is a key factor for the successfulness of the drilling operations, especially when dealing with narrow mud-weight windows. Poor management of ECD can result in unsafe and/or inefficient drilling as well as an increase in drilling cost due to associated nonproductive time (NPT). Different parameters can affect the ECD directly or indirectly including, but not limited to, wellbore geometry, cuttings, hole cleaning efficiency, flow rate, and rheological properties of the drilling fluid. However, the magnitude of the effect of each parameter is not well understood. In this paper, a comprehensive statistical analysis using the correlation coefficient was conducted using real field data to investigate the effect of three controllable factors - solid contents (SC), yield point (Yp), and plastic viscosity (PV) - on ECD.
The recent and rapid success of using high viscosity friction reducers (HVFRs) in hydraulic fracturing treatments is due to several advantages over other fracture fluids (e.g. linear gel), which include better proppant carrying capability, induce more complex fracture system network with higher fracture length, and overall lower costs due to fewer chemicals and less equipment on location. However, some concerns remain, like how HVFRs rheological properties can have impact on proppant transport into fractures. The objective of this study is to provide a comprehensive understanding of the influence the rheological characterization of HVFRs have on proppant static settling velocity within hydraulic fracturing process. To address these concerns, comprehensive rheological tests including viscosity profile, elasticity profile, and thermal stability were conducted for both HVFR and linear gel. In the steady shear-viscosity measurement, viscosity behavior versus a wide range of shear rates was studied. Moreover, the influence of elasticity was examined by performing oscillatory-shear tests over the range of frequencies. Normal stress was the other elasticity factor examined to evaluate elastic properties. Also, the Weissenberg number was calculated to determine the elastic to viscous forces. Lastly, quantitative and qualitative measurements were carried out to study proppant settling velocity in the fluids made from HVFRs and linear gel. The results of rheological measurement reveal that a lower concentration of HVFR-2 loading at 2gpt has approximately more than 8 times the viscosity of linear gel loading at 20ppt. Elastic measurement exposes that generally HVFRs have a much higher relaxation time compared to linear gel. Interestingly, the normal stress N1 of HVFR-2, 2gpt was over 3 times that of linear gel loading 20ppt. This could conclude that linear gel fracture fluids have weak elastic characterization compared to HVFR. The results also concluded that at 80 C° linear gel has a weak thermal stability while HVFR-2 loses its properties only slightly with increasing temperature. HVFR-2 showed better proppant settling velocity relative to guar-based fluids. The reduction on proppant settling velocity exceed 75% when HVFR-2 loading at 2gpt was used compared to 20ppt of linear gel. Even though much work was performed to understand the proppant settling velocity, not much experimental work has investigated the HVFR behavior on the static proppant settling velocity measurements. This paper will provide a better understanding of the distinct changes of the mechanical characterization on the HVFRs which could be used as guidance for fracture engineers to design and select better high viscous friction reducers.
Improving sweep efficiency from heterogenous reservoirs necessitates the injection of gel treatment and/or polymer solution to lower the degree of heterogeneity and to lower the mobility ratio, respectively. In this study, three gel systems were compared with partially hydrolyzed polyacrylamide (HPAM) solution. The purpose of this study was to show the ability of the viscoelastic properties of the HPAM to enhance the sweep efficiency compared to the selected gel systems. The model was one quarter of five- spot pattern with one injector and one producer. The injection rate was 525 bbl/day. The selected simulator to run the scenarios was UTGEL, while the selected gel systems were colloidal dispersion gel (CDG), polymer/chromium chloride gel, and polymer/chromium malonate gel. Two polymer concentrations (0.1 and 0.15 wt. %) were used and three salinities were considered (5000, 10,000, and 20,000 mg/l).
This study showed interesting results regarding the ability of the viscoelastic properties of the HPAM polymer solution to yield recovery factors close or similar to those recovery factors obtained from the selected polymer gel systems. The results also revealed that lowering the salinity of post-treatment water could boost the performance of the polymer solution and make the polymer flooding more effective than gel systems. The results also showed that regardless the duration of injecting the polymer gel system, the HPAM polymer solution still yielded promising results, particularly if low-salinity water was implemented after the treatment.
Drilling fluid design for shale plays aims to prevent wellbore instability problems associated with fluid invasion, shale swelling, and cuttings dispersion. Although oil-based mud (OBM) can be used to achieve these goals, environmental and economic concerns limit its application. This research evaluates the potential of using silica nanoparticles (SiO2-NPs) and graphene nanoplatelets (GNPs) as drilling fluid additives in a single formulation to improve shale inhibition and long-term stability of water-based mud (WBM) against temperature effects. The design of the nanoparticle water-based mud (NP-WBM) followed a customized approach that selects the additives according to the characteristics of the reservoir. Characterization of Woodford shale was completed with X-ray diffraction (XRD), cation exchange capacity (CEC), and scanning electron microscopy (SEM). The aqueous stability test and zeta-potential measurements were used to assess the stability of the NPs. NP-WBM characterization included the analysis of the rheological properties measured with a rotational viscometer and the evaluation of the filtration trends at low-temperature/low-pressure (LTLP) and high-temperature/high-pressure (HTHP) conditions. Additionally, dynamic aging was performed at temperatures up to 250°F for thermal stability evaluation. Finally, chemical-interaction tests such as cutting dispersion and bulk swelling helped to analyze the effect of introducing NPs on the inhibition capabilities of the WBM. Conventional KCl/PHPA fluid was used for comparison purposes. The results of this investigation revealed that SiO2-NPs and GNPs acted synergistically with other additives to improve the filtration characteristics of the WBM with only minor effects on the rheological properties. NPs exhibited a high colloidal stability with ζ-potential values below-30 mV, which warrants their dispersion within the WBM at an optimal concentration of 0.75 wt.%. The high thermal conductivity of NPs played a key role in promoting an almost flat trend in the cumulative filtrate for the NP-WBM at aged conditions, whereas KCl/PHPA suffered a drastic increase. Also, NP-WBM preserved 43.97% of its initial cutting carrying capacity, while KCl/PHPA experienced a severe reduction of 95.24% at extreme conditions (250°F). Despite the high illite content of the Woodford shale, the NP-WBM exhibited superior inhibition properties that reduced cutting erosion and swelling effect by 24.48% and 35.24%, respectively, compared to the KCl/PHPA fluid. Overall, this investigation supports the potential use of nanomaterials to enhance the inhibition capabilities and the long-term stability of WBM for unconventional shales, presenting an eco-friendly alternative for harsher environments.
Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Flori, Ralph E. (Missouri University of Science and Technology) | Alsaba, Mortadha T. (Australian College of Kuwait) | Amer, Ahmed S. (Newpark Technology Center/ Newpark Drilling Fluids) | Al-Bazzaz, Waleed H. (Kuwait Institute for Scientific Research)
Lost circulation is a unique challenge unlike other factors contributing to non-productive time (NPT). Due to the variability in the nature and type of lost circulation prone formations; there is no universal solution to this challenge. This publication presents a new approach to guide the decision-making process of which and when to apply a certain treatment as compared to another. If implemented correctly, a significant reduction in NPT related to lost circulation can be expected. Also, the cost of each treatment, as well as the NPT that is associated with the treatment, were examined in this study. Lost circulation events for three formations which are the Dammam, Hartha, and Shuaiba were gathered from over 1000 wells drilled in Basra oil fields, Iraq using various sources and reports; the treatments were classified by scenario –partial, severe, and complete losses – as well as cost, efficiency, and formation types. This paper is developed based on probabilities, expected monetary value (EMV), and decision tree analysis (DTA) to recommend the best-lost circulation strategy for each type of losses.
This paper utilizes probability and economics in the decision-making process. This is the first study that considers a detailed probability and cost to treat the lost circulation problem. Thousands of treatment scenarios for each type of losses are conducted, and the EMVs for all scenarios are calculated. For each type of losses, the lowest EMV treatment strategy- that is practically applicable in the field and makes sense- is selected to be used to treat each type of losses to minimize NPT and cost. If the losses didn't stop after utilizing the proposed treatment strategies, it is recommended to use liner hanger to isolate the losses zone and then continue drilling. A change in well design is also suggested to help to minimize NPT and cost. In addition, a formalized methodology for responding to losses in the Dammam, Hartha, and Shuaiba formations is established and provided as means of assisting drilling personnel to work through the lost circulation problem in a systematic way.
One challenge in drilling wells in Basra oil fields is the inconsistency of approaches to the lost circulation problem. Therefore, the result of this data analysis provides a path forward for the Basra area lost circulation events and suggests probable methods that can be used in similar formations globally. Additionally, the methodology can be adapted to studying other types of formations and drilling challenges have the same geological properties in any major oil field.