Performance evaluation of synthetic and natural polymers in nitrogen foam-based fracturing fluids in the Cooper Basin, South Australia

2020 ◽  
Vol 60 (1) ◽  
pp. 227
Author(s):  
Tuan Tran ◽  
M. E. Gonzalez Perdomo ◽  
Klaudia Wilk ◽  
Piotr Kasza ◽  
Khalid Amrouch
Keyword(s):  
High Temperature ◽  
Foam Stability ◽  
South Australia ◽  
Propagation Model ◽  
Natural Polymers ◽  
Fracturing Fluid ◽  
Additional Energy ◽  
Fracturing Fluids ◽  
Nitrogen Foam ◽  
Cooper Basin

Hydraulic fracturing is a well-known stimulation technique for creating fractures in a subsurface formation to achieve profitable production rates in low-permeability reservoirs. Slickwater has been widely used as a traditional fracturing fluid. However, it has multiple disadvantages, such as high consumption of water, clay swelling and low flowback recovery. Foam, as an alternative fracturing fluid, consumes less liquid and provides additional energy. However, foam bubbles are typically unstable due to the degradation of surfactants, particularly in high temperature reservoirs, which reduces their capabilities of carrying and placing proppants into fractures. The purpose of this study is to provide general guidelines for an optimised application of polymers to improve the foam stability in high temperature reservoirs while increasing the proppant placement and water usage efficiencies. In this paper, the effects of natural hydroxypropyl guar (HPG) and synthetic polyacrylamide (PAM) polymers on the rheological properties of nitrogen foam-based fluids were examined by laboratory experiments conducted using temperatures up to 110°C. Then, a 3D hydraulic fracture propagation model was developed to study the fracturing performance of HPG-foamed and PAM-foamed fluids in the Toolachee Formation, Cooper Basin. It was found that synthetic PAM polymers were more effective than natural HPG polymers in stabilising foam viscosity under high temperature conditions. The simulation results indicate that foam-based fluids totally outperform slickwater in the field case application. This paper emphasises the significance of crosslinkers, foam quality and thermal stability on the performance of foams in high temperature environments.

Simulation of hydraulic fracturing with propane-based fluid using a fracture propagation model coupled with multiphase flow simulation in the Cooper Basin, South Australia

2016 ◽  
Vol 56 (1) ◽  
pp. 415 ◽  
Author(s):  
Yang Fei ◽  
Mary Gonzalez Perdomo ◽  
Viet Quoc Nguyen ◽  
Zhongyu Lei ◽  
Kunakorn Pokalai ◽  
...  
Keyword(s):  
Multiphase Flow ◽  
South Australia ◽  
Fracture Propagation ◽  
Flow Simulation ◽  
Gas Production ◽  
Propagation Model ◽  
Unconventional Reservoirs ◽  
Fracturing Fluids ◽  
Water Based ◽  
Cooper Basin

In many unconventional reservoirs, gas wells do not perform to their potential when water-based fracturing fluids are used for treatments. The sub-optimal fracture productivity can be attributed to many factors such as effective fracture length loss, low load fluid recovery, flowback time, and water availability. The development of unconventional reservoirs has, therefore, prompted the industry to reconsider waterless fracturing treatments as viable alternatives to water-based fracturing fluids. In this paper, a simulation approach was used by coupling a fracture propagation model with a multiphase flow model. The Toolachee Formation is a tight sand in the Cooper Basin, around 7,200 ft in depth, and has been targeted for gas production. In this study, a 3D hydraulic fracture propagation model was first developed to provide fracture dimensions and conductivity. Then, from an offset well injection fall off test, the model was tuned by using different calibration parameters such as fracture gradient and closure pressure to validate the model. Finally, fracture propagation model outputs were used as the inputs for multiphase flow reservoir simulation. A large number of cases were simulated based on different fraccing fluids and the concept of permeability jail to represent several water-induced damage effects. It was found that LPG was a successful treatment, especially in a reservoir where the authors suspected the presence of permeability jails. The authors also observed that total flowback recovery approached 76% within 60 days in the case of using gelled LPG. Modelling predictions also support the need for high-quality foam, and LPG can be expected to bring long-term productivity gains in normal tight gas relative permeability behaviour.

Design and Application of High-Temperature Raw-Seawater-Based Fracturing Fluids

SPE Journal ◽  
2019 ◽  
Vol 24 (04) ◽  
pp. 1929-1946 ◽  
Author(s):  
Tariq Almubarak ◽  
Mohammed AlKhaldi ◽  
Jun Hong Ng ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
High Temperature ◽  
Calcium Sulfate ◽  
Ph Value ◽  
Fracturing Fluid ◽  
Remote Areas ◽  
Fracturing Fluids ◽  
High Pressure High Temperature ◽  
Negative Effect ◽  
Static Conditions ◽  
First Time

Summary Typically, water-based fracturing treatments consume a large volume of fresh water. Providing consistent freshwater sources is difficult and sometimes not feasible, especially in remote areas and offshore operations. Therefore, several seawater-based fracturing fluids have been developed in an effort to preserve freshwater resources. However, none of these fluids minimizes fracture-face skin and proppant-conductivity impairment, which can be critical for unconventional well treatments. Several experiments and design iterations were conducted to tailor raw-seawater-based fracturing fluids. These fluids were designed to have rheological properties that can transport proppant under dynamic and static conditions. The optimized seawater-based fracturing-fluid formulas were developed such that no scale forms when additives are mixed in or when the fracturing-fluid filtrate is mixed with different formation brines. The tests were conducted using a high-pressure/high-temperature (HP/HT) rheometer, coreflood, and by aging cells at 250 to 300°F. The developed seawater-based fracturing fluids were optimized with an apparent viscosity greater than 100 cp at a shear rate of 100 seconds–1 and a temperature of 300°F for more than 1 hour. The use of polymeric- and phosphonate-based scale inhibitors (SIs) prevented the formation of severe calcium sulfate (CaSO4) scale in mixtures of seawater and formation brines at 300°F. Controlling the pH of fracturing fluids prevented magnesium and calcium hydroxide precipitation that occurs at a pH value of greater than 9.5. Most importantly, SIs had a negative effect on the viscosity of seawater fracturing fluid during testing because of their negative interaction with metallic crosslinkers. The developed seawater-based fracturing fluids were applied for the first time in an unconventional and a conventional carbonate well and showed very promising results; details of field treatments are discussed in this paper.

Monitoring shale gas resources in the Cooper Basin using magnetotellurics

Geophysics ◽  
2016 ◽  
Vol 81 (6) ◽  
pp. A13-A16 ◽  
Author(s):  
Nigel Rees ◽  
Simon Carter ◽  
Graham Heinson ◽  
Lars Krieger
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
South Australia ◽  
Depth Range ◽  
Bulk Conductivity ◽  
Gas Reservoirs ◽  
Horizontal Fracture ◽  
Fluid Permeability ◽  
Fracturing Fluids ◽  
Cooper Basin

The magnetotelluric (MT) method is introduced as a geophysical tool to monitor hydraulic fracturing of shale gas reservoirs and to help constrain how injected fluids propagate. The MT method measures the electrical resistivity of earth, which is altered by the injection of fracturing fluids. The degree to which these changes are measurable at the surface is determined by several factors, such as the conductivity and quantity of the fluid injected, the depth of the target interval, the existing pore fluid salinity, and a range of formation properties, such as porosity and permeability. From an MT monitoring survey of a shale gas hydraulic fracture in the Cooper Basin, South Australia, we have found temporal and spatial changes in MT responses above measurement error. Smooth inversions are used to compare the resistivity structure before and during hydraulic fracturing, with results showing increases in bulk conductivity of 20%–40% at a depth range coinciding with the horizontal fracture. Comparisons with microseismic data lead to the conclusion that these increases in bulk conductivity are caused by a combination of the injected fluid permeability and an increase in wider scale in situ fluid permeability.

scholarly journals Experimental and Simulation Studies of Energized Fracturing Fluid Efficiency in Tight Gas Formations

Energies ◽  
2019 ◽  
Vol 12 (23) ◽  
pp. 4465
Author(s):  
Klaudia Wilk
Keyword(s):  
Clay Minerals ◽  
Guar Gum ◽  
Laboratory Data ◽  
Good Alternative ◽  
Rheological Parameters ◽  
Fracturing Fluid ◽  
Additional Energy ◽  
Negative Results ◽  
Fracturing Fluids ◽  
Water Based

The use of water-based fracturing fluids during fracturing treatment can be a problem in water-sensitive formations due to the permeability damage hazard caused by clay minerals swelling. The article includes laboratory tests, analyses and simulations for nitrogen foamed fracturing fluids. The rheology and filtration coefficients of foamed fracturing fluids were examined and compared to the properties of conventional water-based fracturing fluid. Laboratory results provided the input for numerical simulation of the fractures geometry for water-based fracturing fluids and 50% N2 foamed fluids, with addition of natural, fast hydrating guar gum. The results show that the foamed fluids were able to create shorter and thinner fractures compared to the fractures induced by the non-foamed fluid. The simulation proved that the concentration of proppant in the fracture and its conductivity are similar or slightly higher when using the foamed fluid. The foamed fluids, when injected to the reservoir, provide additional energy that allows for more effective flowback, and maintain the proper fracture geometry and proppant placing. The results of laboratory work in combination with the 3D simulation showed that the foamed fluids have suitable viscosity which allows opening the fracture, and transport the proppant into the fracture, providing successful fracturing operation. The analysis of laboratory data and the performed computer simulations indicated that fracturing fluids foamed by nitrogen are a good alternative to non-foamed fluids. The N2-foamed fluids exhibit good rheological parameters and proppant-carrying capacity. Simulated fracture of water-based fracturing fluid is slightly longer and higher compared to foamed fluid. At the same time, when using a fluid with a gas additive, the water content in fracturing fluid is reduced which means the minimization of the negative results of the clay minerals swelling.

scholarly journals Research Progress of High Temperature Resistant Fracturing Fluid System

2021 ◽  
Vol 2076 (1) ◽  
pp. 012039
Author(s):  
Ke Xu ◽  
Yongjun Lu ◽  
Jin Chang ◽  
Yang Li
Keyword(s):  
High Temperature ◽  
Oil And Gas ◽  
Guar Gum ◽  
Crosslinking Agent ◽  
Research Progress ◽  
Fracturing Fluid ◽  
Fluid System ◽  
Fracturing Fluids ◽  
Ultra High Temperature ◽  
Exploration And Development

Abstract China has made significant progress in the efficient exploration and development of deep-seated oil and gas wells. Reservoir reformation, as the core tool of high-temperature deep-seated exploration and development, puts forward a strong demand for fracturing fluids. The ultra-high temperature fracturing fluid system developed in my country is mainly divided into two types: ultra-high temperature guar gum fracturing fluid and ultra-high temperature synthetic polyacrylamide fracturing fluid. The high temperature resistant fracturing fluid system is mainly composed of high temperature resistant thickener, high temperature resistant crosslinking agent and temperature stabilizing additives and other additives. Based on indoor research and a large amount of literature, this article summarizes the research and application of high temperature resistant fracturing fluid system, high temperature resistant thickener, high temperature resistant crosslinking agent and temperature stabilizing additives in my country in recent years, and pointed out the shortcomings and limitations of the high-temperature fracturing fluid, the technical direction of the development of high-temperature resistant fracturing fluid technology is proposed.

Fracturing Fluid Design: A Closer Look at Breaker and Surfactant Selection

2021 ◽  
Author(s):  
Basil Alfakher ◽  
Ali Al-Taq ◽  
Sajjad Aldarweesh ◽  
Luai Alhamad
Keyword(s):  
Surface Tension ◽  
High Temperature ◽  
Ammonium Persulfate ◽  
Post Treatment ◽  
Berea Sandstone ◽  
Chemical Additives ◽  
Fracturing Fluid ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Fracturing Fluids

Abstract Guar and its derivatives are the most commonly used gelling agents for fracturing fluids. At high temperature, higher polymer loadings are required to maintain sufficient viscosity for proper proppant carry and creating the fracture geometry. To minimize fracturing fluids damage and optimize fracture conductivity, it is necessary to design a fluid that is easy to clean up by ensuring proper breaking and sufficiently low surface tension for flow back. Therefore, breakers and surfactants must be carefully selected and optimally dosed to ensure the success of fracturing treatments. In this study, two fracturing fluids were evaluated for moderate to high temperature applications with a focus on post-treatment cleanup efficiency. The first is a guar-based fluid with a borate crosslinker evaluated at 280°F and the second is a CMHPG-based fluid with a zirconate crosslinker evaluated at 320°F. The shear viscosities of both fluids were tested with a live sodium bromate breaker, a polymer encapsulated ammonium persulfate breaker and a dual breaker system combining the two breakers. Different anionic and nonionic surfactant chemistries (aminosulfonic acid and alcohol based) were investigated by measuring surface tension of the surfactant solutions at different concentrations. The compatibility of the surfactants with other fracturing fluid additives and their adsorption in Berea sandstone was also investigated. Finally, the damage caused by leak-off for each fracturing fluid was simulated by using coreflooding experiments and Berea sandstone core plugs. Lab results showed the guar and CMHPG fluids maintained sufficient viscosity for the first two hours at baseline, respectively. The encapsulated breaker proved to be effective in delaying the breaking of the fracturing fluids. The dual breaker system was the most effective and the loading was optimized for each tested temperature to provide the desired viscosity profile. Two of the examined surfactants were effective in lowering surface tension (below 30 dyne/cm) and were stable for all tested temperatures. The guar broken fluid showed better regained permeability (up to 94%) when compared to the CMHPG (up to 53%) fluid for Berea sandstone. This paper outlines a methodical approach to selecting and optimizing fracturing fluid chemical additives for better post-treatment cleanup and subsequent well productivity.

A High Density Fracturing Fluid System for HPHT Reservoir Stimulation Treatment

2013 ◽  
Vol 680 ◽  
pp. 312-314
Author(s):  
Ping Li Liu ◽  
Qi Zhu ◽  
Xi Jin Xing
Keyword(s):  
High Temperature ◽  
Petroleum Industry ◽  
Temperature Stability ◽  
High Density ◽  
Fracturing Fluid ◽  
Fluid System ◽  
Shear Properties ◽  
Proppant Transport ◽  
Reservoir Stimulation ◽  
Fracturing Fluids

Petroleum industry is focusing on HPHT reservoir. In high-temperature conditions, fracturing fluids especially need to be stable and induce minimum damage, and have good proppant transport capabilities. In order to overcome these problems, a novel high density fracturing fluid system has been developed whose density can reach up to 1.21 g/cm3. This paper summarizes a study on formulating weighted agent, and extensive studies were also conducted to determine temperature stability and anti-shear properties and compatibility with additives.

Study and Application of Shallow Water Fracturing Fluid in High Temperature Deep Carbonate Reservoir

2013 ◽  
Author(s):  
Mingguang Che ◽  
Yonghui Wang ◽  
Xingsheng Cheng ◽  
Yongjun Lu ◽  
Yongping Li ◽  
...  
Keyword(s):  
High Temperature ◽  
Shallow Water ◽  
Carbonate Reservoir ◽  
Fracturing Fluid

scholarly journals Laboratory Testing of Fracture Conductivity Damage by Foam-Based Fracturing Fluids in Low Permeability Tight Gas Formations

Energies ◽  
2021 ◽  
Vol 14 (6) ◽  
pp. 1783
Author(s):  
Klaudia Wilk-Zajdel ◽  
Piotr Kasza ◽  
Mateusz Masłowski
Keyword(s):  
Hydraulic Fracturing ◽  
Guar Gum ◽  
Polymer Concentration ◽  
Laboratory Research ◽  
Damage Effect ◽  
Tight Gas ◽  
Fracturing Fluid ◽  
Fracture Conductivity ◽  
Fracturing Fluids ◽  
Sandstone Rock

In the case of fracturing of the reservoirs using fracturing fluids, the size of damage to the proppant conductivity caused by treatment fluids is significant, which greatly influence the effective execution of hydraulic fracturing operations. The fracturing fluid should be characterized by the minimum damage to the conductivity of a fracture filled with proppant. A laboratory research procedure has been developed to study the damage effect caused by foamed and non-foamed fracturing fluids in the fractures filled with proppant material. The paper discusses the results for high quality foamed guar-based linear gels, which is an innovative aspect of the work compared to the non-foamed frac described in most of the studies and simulations. The tests were performed for the fracturing fluid based on a linear polymer (HPG—hydroxypropyl guar, in liquid and powder form). The rheology of nitrogen foamed-based fracturing fluids (FF) with a quality of 70% was investigated. The quartz sand and ceramic light proppant LCP proppant was placed between two Ohio sandstone rock slabs and subjected to a given compressive stress of 4000–6000 psi, at a temperature of 60 °C for 5 h. A significant reduction in damage to the quartz proppant was observed for the foamed fluid compared to that damaged by the 7.5 L/m3 natural polymer-based non-foamed linear fluid. The damage was 72.3% for the non-foamed fluid and 31.5% for the 70% foamed fluid, which are superior to the guar gum non-foamed fracturing fluid system. For tests based on a polymer concentration of 4.88 g/L, the damage to the fracture conductivity by the non-foamed fluid was 64.8%, and 26.3% for the foamed fluid. These results lead to the conclusion that foamed fluids could damage the fracture filled with proppant much less during hydraulic fracturing treatment. At the same time, when using foamed fluids, the viscosity coefficient increases a few times compared to the use of non-foamed fluids, which is necessary for proppant carrying capacities and properly conducted stimulation treatment. The research results can be beneficial for optimizing the type and performance of fracturing fluid for hydraulic fracturing in tight gas formations.

Sign in / Sign up

Export Citation Format

Share Document