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) | Al-Alwani, Mustafa A. (Missouri University of Science and Technology) | Lian, David (Missouri University of Science and Technology) | Al-Bazzaz, Waleed H. (Kuwait Institute For Scientific Research)
It is not easy to obtain an optimal hole cleaning for the drilling operation because of the complicated relationship between the drilling parameters influencing hole cleaning. The two viscosity components (e.g. plastic viscosity (PV) and yield point (YP)) and the flow rate (Q) are essential parameters for effective hole cleaning. Thus, understanding the relationship between those parameters will contribute to efficient hole cleaning. The aim of this paper is to explore those relationships to provide optimal hole cleaning.
Descriptive data analytics was conducted for data of more than 2000 wells drilled in Southern Iraq. The data were first cleansed and outliers were removed using visual inspection and box plots. The Pearson correlation (PC), a widely used method to measure the linear relationship between two parameters, was utilized to access the relationships between PV and Q, YP and Q, and YP/PV and Q. Moreover, a 10% sensitivity analysis was escorted to quantify and comprehend those relationships.
The PCs were calculated to be 0.5, 0.076, and 0.22 for the relationships between YP, PV, and YP/PV with Q, respectively. YP had the highest direct relationship with Q, while PV had the lowest. When the YP increases, a sufficient Q has to be provided to initiate the flow and maintain the mud cycle. In addition, to prevent large solid particles from settling due to the slip velocity, sufficient annular and particle velocities have to be achieved. After initiating the flow, an increase in flow rate to overcome resistance due to PV will not be significant. Therefore, YP has more effect on Q than PV. To maximize hole cleaning, thickening ratio (YP/PV) should be increased. This requires an increase in flow rate, which can be quantified by using the sensitivity analysis provided to achieve the required Q for any increase in YP/PV.
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) | Al-Alwani, Mustafa A. (Missouri University of Science and Technology) | Lian, David (Missouri University of Science and Technology)
Flow rate (Q) affects many drilling operations and parameters such as equivalent circulation density (ECD), hoisting and lowering the drillstring, and breaking gel strength during circulation. The aim of this work is to understand the relationship between ECD and Q based on flow regimes (e.g. laminar, transitional, and turbulent) to avoid or at least minimize the unwanted consequence during drilling practice.
Field data from over 2000 wells drilled in Iraq were collected and analyzed to identify the physical relationship between flow regimes and ECD to enhance the drilling rates. After visualizing the whole dataset, a decision was made to break down the data into three parts based on flow regimes (e.g. laminar, transitional, and turbulent). Descriptive data mining techniques were utilized to establish the relationship between flow regimes and ECD. By achieving better control of ECD in the well, not only faster and cheaper operations are possible, but also safety will be improved.
Previous studies and literature showed that flow regimes can tremendously affect ECD. Many studies have been conducted to understand the relationship between Q and ECD. Nevertheless, the consideration of flow regimes was not implemented in these studies. Inconsistency in the literature results was identified, some concluded the relationship between Q and ECD to be direct, and others showed it to be inverse. Thus, this paper will eliminate this discrepancy in the literature, and it will show that the flow regimes have a pivotal role in the relationship between Q and ECD.
The results of this paper showed that if the flow regime is laminar, the relationship between ECD and Q is inverse. However, in transitional and turbulent flow regimes, the relationship between ECD and Q is direct. That is because, in the laminar flow regime, the cutting will fall out of suspension due to low Q, which will cause a cutting bed to be built and decreases ECD. As Q increases (entering the transitional and turbulent flows) the cutting bed will be eroded, and most of the cuttings will be suspended in the fluid which will increase ECD.
This study examines and expands the understanding between how the characteristics of flow regimes affect ECD. Additionally, this paper will eliminate the discrepancy in the literature about this relationship between ECD and Q.
Alhuraishawy, Ali K. (Iraqi Ministry of Oil / Reservoir and Fields Development Directorate) | Jaber, Ahmed Khalil (Iraqi Ministry of Oil / Reservoir and Fields Development Directorate) | Aljawad, Sameer Noori (Iraqi Ministry of Oil / Reservoir and Fields Development Directorate) | Bai, Baojun (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Baker, Hussein Ali (Baghdad University) | AL-Bazzaz, Waleed Hussien (Kuwait Institute for Scientific Research)
The limitations of oil recovery from carbonate reservoirs are fractures and oil-wet conditions. To overcome the reservoir heterogeneities and reduce fracture transmissibility, preformed particle gel was applied in injector wells. Experimentally, low salinity waterflooding was applied to change the core wettability from oil-wet to water wet for enhanced oil recovery. However, both processes have limitations that cannot be resolved using a single method. A nonuniform fracture width and uniform fracture width models were built using carbonate cores to evaluate the coupling low salinity waterflooding and preformed particle gel in fractured cores and how could be used to improve in-depth water diversion treatment. The results showed that low salinity waterflooding improved in-depth water diversion when injected after PPG directly while seawater showed less effect than low salinity waterflooding. Also, the uniformity of fracture had a significant effect on plugging efficiency oil recovery factor from fractured reservoirs.
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.
Al-Alwani, Mustafa A. (Missouri University of Science and Technology) | Britt, Larry K. (NSI Fracturing) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Al-Attar, Atheer M. (Enterprise Products)
The goal of any hydraulic fracturing stimulation is to design and execute the appropriate treatment that is best suited for the stimulated reservoir. Selecting the best treatment must achieve the desired fracture geometry to maximize long-term well productivity and reserve recovery. The main objective of this study is to conduct detailed short and long-term production and well-to-well comparisons of the different types of fracture stimulation fluids in the Marcellus Shale play.
A database of more than 4,000 wells was integrated for this study. The wells were divided into four groups: water, gel, cross-linked, and hybrid fracs. Chemical data from FracFocus were gathered and processed then coupled with completion and production data to investigate the gas short and long-term production. Detailed monthly production data for the participating wells were captured from DrillingInfo database and utilized in this study.
This paper reports and compares the Marcellus gas initial production, the gas cumulative of the first month, first 6 months, first year, 2 years, and 5 years. The well productivity is tied to each hydraulic fracturing fluid type. The paper provides insights into the different completion trends in the Marcellus as well as the variations in stimulation parameters such as the volume of stimulation fluid and the amount of pumped proppants. The completion aspects of perforated lateral length are also taken into consideration and a comparison of the normalized production and stimulation parameters is also presented. The study shows that water fracturing fluids outperformed the other types of hydraulic fracturing fluids.
This paper introduces several data processing workflows that serve as a reference for individuals who are interested in mining and processing FracFocus database. It also documents the change in hydraulic fracturing fluid types and measures the effects of the fracturing fluid volume and total proppant pumped on the initial and cumulative production.
Fakher, Sherif (Missouri University of Science and Technology)
Carbon dioxide (CO2) injection has recently been applied as an enhanced oil recovery (EOR) method to increase oil recovery from unconventional shale reservoirs. Many interactions will impact the success or failure of this EOR method. This research experimentally investigates the impact of two of these interactions, including asphaltene pore plugging and CO2 adsorption, on the success of CO2 EOR in unconventional shale reservoirs. Two sets of experiments were designed to study the asphaltene pore plugging and CO2 adsorption. The impact of varying CO2 injection pressure, temperature, oil viscosity, and filter membrane pore size on asphaltene pore plugging was investigated. Pertaining to the adsorption experiments, the impact of varying CO2 injection pressure, temperature, and shale particle size was investigated. Asphaltene pore plugging was found to be extremely severe especially in the smaller pore sizes, which indicates that asphaltene poses a serious problem when producing from unconventional nanopores. As the oil viscosity decreased, the asphaltene concentration in the oil decreased as well which made the asphaltene pore plugging less severe in the lower viscosity oils. The thermodynamic conditions, including pressure and temperature, also had a strong impact on asphaltene stability and pore plugging. When undergoing the CO2 adsorption experiments, it was found that increasing the CO2 injection pressure resulted in an increase in adsorption capacity to a certain limit beyond which no further adsorption will be possible. Increasing the temperature resulted in the CO2 molecules becoming highly active which in turn resulted in a decrease in the adsorption capacity significantly. Since experiments were conducted using shale particles, as opposed to an actual shale core, it was important to investigate the accuracy of the results by varying the shale particle size. It was found that as long as the void space volume was measured accurately using helium, the shale particle size had a negligible effect on the adsorption values. This research systematically investigates the impact of two significant interactions on the success of CO2 injection in unconventional shale reservoirs, and studies the impact of several factors within these interactions to determine the extent to which they may influence the success of this EOR method.
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.
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.