How to Make Sensitive Formations Produce Oil: Case Study of the Complex Laboratory Approach to Stimulation Fluid Optimization

2021 ◽  
Author(s):  
Omar Matar ◽  
Hamed AlGhadhban ◽  
Hassan AlDurazi ◽  
Eyad Ali ◽  
Ahmed AlJanahi ◽  
...  
Keyword(s):  
Low Temperature ◽  
Laboratory Testing ◽  
Drilling Fluid ◽  
Laboratory Research ◽  
Potential Contribution ◽  
Fracturing Fluid ◽  
Polymer Loading ◽  
Water Based ◽  
High Concentrations ◽  
Fluid Optimization

Abstract The Bahrain field is one of the oldest developed oil fields in the Middle East, with over a dozen formations in production since the early 1930s. Currently, development of the shallow zones (<2,000 ft) of the Magwa and Ostracod formations is a challenge due to the unique complexity and extreme clay sensitivity. With previous fracturing attempts showing limited success, enhanced laboratory testing was undertaken to make fracturing treatments economic. Formation stabilization improvement is crucial in certain reservoir mineralogies, especially those with exposed shale streaks and high concentrations of clays that exhibit extremely high brine sensitivity. Lack of adequate stabilization of sensitive clays and shales risks the deconsolidation of those minerals into fines that may potentially damage the conductivity of the proppant pack in fracturing operations. Many problems associated with the use of water-based fluids in fracturing operations are caused by incompatibilities between the fracturing fluid and the shale minerals, resulting in a fines migration problem in the relatively low-permeability reservoir and a production decline after the fracturing operation. A scientific approach was applied to the selection of novel shale inhibitors to be used in fracturing applications. First, a laboratory testing program was followed to incorporate a new shale inhibitor into the fracturing fluid system. The fluid recipe was further optimized with a reduction in polymer loading, maximizing breaker concentration and ensuring fast shear recovery, because the stimulation design called for large-size proppant (up to 12/20 mesh) to be used in a low-temperature (124°F) environment. The laboratory results demonstrated that the new shale inhibitor significantly reduces alteration of the permeability of the treated core and improves shale stability. The new inhibitor was deployed in the field, as documented in several case histories. Production results of the treated wells demonstrated several-folds increase in production when compared to previously attempted proppant fracturing treatments. The pilot stimulation campaign proved the value of the laboratory research and brought on line two formations with large potential contribution to Bahrain's overall oil production. Although there is a substantial amount of literature on shale inhibition with water-based drilling fluid, the importance of the shale inhibition and the problems associated with shale reactivity during the fracturing operation remain largely unexplored. This paper presents the complex laboratory approach to stimulation fluid optimization in the Bahrain field. The novel solutions and comprehensive workflow description will benefit a broad variety of projects worldwide targeting water-sensitive or low-temperature formations that represent challenges to fracturing fluid selection.

scholarly journals The Experimental Study on a New Type Low Temperature Water- based Composite Alcohol Drilling Fluid

2014 ◽  
Vol 73 ◽  
pp. 276-282 ◽  
Author(s):  
N.I. Nikolaev ◽  
Liu Tianle ◽  
Wang Zhen ◽  
Jiang Guosheng ◽  
Sun Jiaxin ◽  
...  
Keyword(s):  
Experimental Study ◽  
Low Temperature ◽  
Drilling Fluid ◽  
Water Based ◽  
New Type ◽  
Temperature Water

A Success of Modified Water Based Mud as Drilling Fluid Optimization to Drill Shale Formation at South-S Wells

2021 ◽  
Author(s):  
Dwie Hadinata ◽  
Yuliawan Mulia ◽  
Theodore Rudyanto ◽  
Adi Laharan ◽  
Poultje Haurissa ◽  
...  
Keyword(s):  
Laboratory Test ◽  
Drilling Fluid ◽  
Exchange Capacity ◽  
Lessons Learned ◽  
Comprehensive Method ◽  
Water Based ◽  
Shale Formation ◽  
Fluid Optimization ◽  
Drilling Time ◽  
Cost Economic

Abstract This paper is to explain the optimization of using Modified Shale Inhibitor Water Based Mud (WBM) to drill up to 5,500 ft interval of K-formation reactive shale on South-S Gas Wells. By combining a comprehensive method consists of drilling fluid laboratory test and lessons learned in S area, the optimization was done by determining the amount or concentration of Polyamine & KCl combination, pure Polyamine, Polyamine & NaCl combination, and Pure KCl-Polymer in WBM system as a shale inhibitor. The comparison of shale inhibitor compositions were made by comparing the achieved optimization of drilling fluid program such as drilling time, cost economic, and environment aspect. The basic idea of the WBM optimization was to improve drilling time during drill 5,000 ft footage in 12-1/4" hole section in reactive shale formation as per drilling program. Laboratory test consists of Linear swelling meter with various parameter concentration of Polyamine & KCl combination, pure Polyamine, Polyamine & NACl combination, and Pure KCl-Polymer in WBM system as a shale inhibitor and cation exchange capacity test (CEC or MBT) was done using composite of offset well shale cutting. Experience showed that on 12-1/4" hole section, while facing reactive shale (CEC 18 - 24 meq/100 gr) from K-formation on South-S, modified WBM was proven to eliminate reactive shale issues and lead to budget saving without environmental issues.

Rheological Properties of Water Based Drilling Fluid in Deep Water Drilling Conditions

2013 ◽  
Vol 318 ◽  
pp. 507-512 ◽  
Author(s):  
Qian Sheng Yue ◽  
Qing Zhi Yang ◽  
Shu Jie Liu ◽  
Bao Sheng He ◽  
You Lin Hu
Keyword(s):  
Low Temperature ◽  
Rheological Property ◽  
Deep Water ◽  
Viscosity Ratio ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Water Soluble ◽  
Water Medium ◽  
Water Based ◽  
Water Base

The rheological property of the drilling fluid was one of the focus problems in deep-water drilling, which was widely concerned. In the article, the viscosity-temperature properties of commonly used water soluble polymeric solution, polymeric brine solution, bentonite slurry, polyacrylamide-potassium chloride drilling fluid with different densities and water-base drilling fluid systems commonly used for China offshore well drillings were studied. 4°C-to-20°C viscosity ratio and 4°C-to-20°C YP ratio were used to judge the thickening level of drilling fluids due to low temperature. The experimental results show that on the condition of without considering the influence of pressure on the rheological property of water-base drilling fluid, its viscosity and yield point raised obviously with the decrease of temperature, but the increase level is proximately the same, its 4°C-to-20°C apparent viscosity ratio is basically within the 1.50. Analysis indicates that the viscosity of water-base drilling fluid depends on the viscosity of dispersed media. The performance of water medium determines the viscosity-temperature property of the water-based drilling fluid. It is proposed that in deep water drillings, if a water-base drilling fluid is used, it is not necessary to emphasize the influence of deep water and low temperature on the flowability. On the condition of guaranteeing wellbore stability and borehole cleaning, it is more suitable for using the water-base drilling fluid with low viscosity and low gel strength for deep water well drillings.

Designing Drilling Fluids to Combat Circulation Losses for Arctic Environments

2015 ◽  
Author(s):  
Mesfin Belayneh ◽  
Bernt S. Aadnøy
Keyword(s):  
Low Temperature ◽  
Laboratory Experiments ◽  
Drilling Fluid ◽  
Drilling Fluids ◽  
Drilling Mud ◽  
Drilling Operation ◽  
Water Based ◽  
Fluid Properties ◽  
Fracture Sealing ◽  
Productive Time

Drilling fluid plays a key role in an efficient drilling operation to minimize problems such as wellbore collapse, circulation losses and stuck pipe. Well instability problems are costly as they increase the non-productive time and the overall budget (1) (2). Well instability problems controlled by designing appropriate mud density and fluid properties that controls the well. The fracture sealing ability of a drilling fluid is one very important of the drilling mud. This paper presents design of water-based drilling fluids and results from laboratory experiments to quantify the loss circulation performance of drilling fluids. Because it is preferable to use oil-based muds in some well sections, the paper will also include a recent study on how to minimize losses when using oil based muds. Here uses of micro/nanoparticles have shown to reduce filtrate losses and to build barriers that are more efficient during circulation loss events. All the tests presented are at low temperature, which is suitable for Artic environments.

Rheological Properties of Water-Based Drilling Fluids in Deep Offshore Conditions

2019 ◽  
Author(s):  
Qian Ding ◽  
Baojiang Sun ◽  
Zhiyuan Wang ◽  
Yonghai Gao ◽  
Yu Gao ◽  
...  
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Low Temperature ◽  
Rheological Properties ◽  
Apparent Viscosity ◽  
Drilling Fluid ◽  
Plastic Viscosity ◽  
Drilling Fluids ◽  
Water Based ◽  
Temperature And Pressure

Abstract In deep-water drilling, the drilling fluid is affected by the alternating temperature field derived from the low temperature of the seawater and the high temperature of the formation. The complicated wellbore temperature and pressure environments make the prediction of rheological properties of the drilling fluid difficult. In this study, the rheological properties of water-based drilling fluid in full temperature and pressure range of deep-water conditions were tested from 2 to 150 °C (35.6 to 302 °F) and 0.1 to 70 MPa (14.5 to 10000psi). The experiment was carried out by the OFI130-77 high temperature and high pressure rheometer. The experimental data were processed by multiple regression analysis method, and the mathematical model for predicting the apparent viscosity, plastic viscosity and yield point of water-based drilling fluid under high temperature and high pressure conditions was established. The experimental results show that when the temperature is lower than 65 °C (149 °F), the apparent viscosity and plastic viscosity of the water-based drilling fluid decrease significantly with increasing temperature. When the temperature is higher than 65 °C (149 °F), the apparent viscosity and plastic viscosity decrease slowly. Under low temperature conditions, the effect of pressure on the apparent viscosity and plastic viscosity of water-based drilling fluids is relatively significant. The calculated values of the prediction model have a good agreement with the experimental measurements. Compared with the traditional model, this prediction model has a significant improvement in the prediction accuracy in the low temperature section, which can provide a calculation basis for on-site application of deepwater drilling fluid.

scholarly journals The Static Laboratory Testing for Fracturing Fluid Optimization

2021 ◽  
Vol 1 (1) ◽  
pp. 219-224
Author(s):  
Boni Swadesi ◽  
Ahmad Sobri ◽  
Dewi Asmorowati ◽  
Mia Feria Helmy ◽  
Ahmad Azhar ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Laboratory Testing ◽  
Oil Well ◽  
Fluid Sample ◽  
Field Scale ◽  
Fracturing Fluid ◽  
Laboratory Assessment ◽  
The Common ◽  
Breaking Time ◽  
Fluid Optimization

Hydraulic fracturing operation is the common method to stimulate an oil well in order to make the permeability around the well become higher by injecting a mixing of fracturing fluid and proppant. Hopefully, this higher permeability can contribute to increase the production of oil and/or gas. The fundamental laboratory assessment of fracturing fluid as a part of injected component is important to be conducted before field scale implementation. One of the fundamental assessment is the static laboratory testing. In this test, the fracturing fluid sample is measured to obtain the data about its properties such as water quality, rheology, crown time and breaking time. These properties give important role to calculate the performance of the hydraulic fracturing field scale operation would be. In this research, we conducted the static laboratory testing for fracturing fluid in sensitivity of concentration which are 35, 40 and 45 systems. Every concentration have been measured its properties in order to compare each other to evaluate and select best fracturing fluid candidate for field scale application.

Potential Contribution of Nutrients and Polycyclic Aromatic Hydrocarbons from the Creeks of Cootes Paradise Marsh

1996 ◽  
Vol 31 (3) ◽  
pp. 485-504 ◽  
Author(s):  
Patricia Chow-Fraser ◽  
Barb Crosbie ◽  
Douglas Bryant ◽  
Brian McCarry
Keyword(s):  
Aromatic Hydrocarbons ◽  
Laboratory Experiments ◽  
Dry Weight ◽  
Common Source ◽  
Potential Contribution ◽  
Nitrogen And Phosphorus ◽  
Engine Combustion ◽  
Polycyclic Aromatic ◽  
High Concentrations ◽  
Derivatives Of

Abstract During the summer of 1994, we compared the physical and nutrient characteristics of the three main tributaries of Cootes Paradise: Spencer, Chedoke and Borer’s creeks. On all sampling occasions, concentrations of CHL α and nutrients were always lowest in Borer’s Creek and highest in Chedoke Creek. There were generally 10-fold higher CHL α concentrations and 2 to 10 times higher levels of nitrogen and phosphorus in Chedoke Creek compared with Spencer Creek. Despite this, the light environment did not differ significantly between Spencer and Chedoke creeks because the low algal biomass in Spencer Creek was balanced by a relatively high loading of inorganic sediments from the watershed. Laboratory experiments indicated that sediments from Chedoke Creek released up to 10 µg/g of soluble phosphorus per gram (dry weight) of sediment, compared with only 2 µg/g from Spencer Creek. By contrast, sediment samples from Spencer Creek contained levels of polycyclic aromatic hydrocarbon that were as high as or higher than those from Chedoke Creek, and much higher than those found in Borer’s Creek. The distribution of normalized PAH concentrations suggests a common source of PAHs in all three tributaries, most likely automobile exhaust, since there were high concentrations of fluoranthene and pyrene, both of which are derivatives of engine combustion.

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.

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