Operational Challenges of Hydraulic Fracturing of Thin, Low Permeability and Highly Sour Reservoirs in the UAE – A NOC Journey

2020 ◽  
Author(s):  
Graham Edmonstone ◽  
Anthony N. Martin ◽  
Nurlan Turniyazov ◽  
Noor Talib ◽  
Hessa Al Shehhi ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Low Permeability

Wettability Alteration to Intermediate Gas-Wetting in Gas-Condensate Reservoirs at High Temperatures

SPE Journal ◽  
2007 ◽  
Vol 12 (04) ◽  
pp. 397-407 ◽  
Author(s):  
Mashhad Mousa Fahes ◽  
Abbas Firoozabadi
Keyword(s):  
Hydraulic Fracturing ◽  
Production Rate ◽  
High Temperatures ◽  
Gas Production ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Absolute Permeability ◽  
Low Permeability ◽  
Gas Well ◽  
Water Blocking

Summary Wettability of two types of sandstone cores, Berea (permeability on the order of 600 md), and a reservoir rock (permeability on the order of 10 md), is altered from liquid-wetting to intermediate gas-wetting at a high temperature of 140C. Previous work on wettability alteration to intermediate gas-wetting has been limited to 90C. In this work, chemicals previously used at 90C for wettability alteration are found to be ineffective at 140C. New chemicals are used which alter wettability at high temperatures. The results show that:wettability could be permanently altered from liquid-wetting to intermediate gas-wetting at high reservoir temperatures,wettability alteration has a substantial effect on increasing liquid mobility at reservoir conditions,wettability alteration results in improved gas productivity, andwettability alteration does not have a measurable effect on the absolute permeability of the rock for some chemicals. We also find the reservoir rock, unlike Berea, is not strongly water-wet in the gas/water/rock system. Introduction A sharp reduction in gas well deliverability is often observed in many low-permeability gas-condensate reservoirs even at very high reservoir pressure. The decrease in well deliverability is attributed to condensate accumulation (Hinchman and Barree 1985; Afidick et al. 1994) and water blocking (Engineer 1985; Cimolai et al. 1983). As the pressure drops below the dewpoint, liquid accumulates around the wellbore in high saturations, reducing gas relative permeability (Barnum et al. 1995; El-Banbi et al. 2000); the result is a decrease in the gas production rate. Several techniques have been used to increase gas well deliverability after the initial decline. Hydraulic fracturing is used to increase absolute permeability (Haimson and Fairhurst 1969). Solvent injection is implemented in order to remove the accumulated liquid (Al-Anazi et al. 2005). Gas deliverability often increases after the reduction of the condensate saturation around the wellbore. In a successful methanol treatment in Hatter's Pond field in Alabama (Al-Anazi et al. 2005), after the initial decline in well deliverability by a factor of three to five owing to condensate blocking, gas deliverability increased by a factor of two after the removal of water and condensate liquids from the near-wellbore region. The increased rates were, however, sustained for a period of 4 months only. The approach is not a permanent solution to the problem, because the condensate bank will form again. On the other hand, when hydraulic fracturing is used by injecting aqueous fluids, the cleanup of water accumulation from the formation after fracturing is essential to obtain an increased productivity. Water is removed in two phases: immiscible displacement by gas, followed by vaporization by the expanding gas flow (Mahadevan and Sharma 2003). Because of the low permeability and the wettability characteristics, it may take a long time to perform the cleanup; in some cases, as little as 10 to 15% of the water load could be recovered (Mahadevan and Sharma 2003; Penny et al. 1983). Even when the problem of water blocking is not significant, the accumulation of condensate around the fracture face when the pressure falls below dewpoint pressure could result in a reduction in the gas production rate (Economides et al. 1989; Sognesand 1991; Baig et al. 2005).

scholarly journals THE TEST RESULTS OF LOW-PERMEABILITY SHALE DEPOSITS WHEN DRILLING THE PRE-CRETACEOUS COMPLEX AT THE KARMALINOVSKOYE GAS CONDENSATE FIELD

2019 ◽  
pp. 45-58
Author(s):  
A. A. Zakharov ◽  
S. V. Korotkov ◽  
A. I. Gritsenko ◽  
R. A. Ivakin ◽  
V. G. Griguletsky
Keyword(s):  
Hydraulic Fracturing ◽  
Flow Rate ◽  
Gas Condensate ◽  
Low Permeability ◽  
Test Results ◽  
North West ◽  
The North ◽  
Exploratory Wells

The article reports the results of the analysis of the field prospecting activities of five exploratory wells at the Karmalinovskoye gas condensate field. We have found that the eastern part of the licensed area is characterized by the lack of fructuring in Paleozoic deposits, and the development of the productive deposit extends in the north-west direction. Hydraulic fracturing made it possible to get a stable gas and gas condensate flow rate in well № 4. This volume exceeds 3,8 times as large than flow rate in wells № 1 and № 2, which were tested after drilling without conducting hydraulic fracturing.

Experimental and numerical investigation into nano-stabilized foams in low permeability reservoir hydraulic fracturing applications

Fuel ◽  
2018 ◽  
Vol 213 ◽  
pp. 133-143 ◽  
Author(s):  
Yang Fei ◽  
Raymond L. Johnson ◽  
Mary Gonzalez ◽  
Manouchehr Haghighi ◽  
Kunakorn Pokalai
Keyword(s):  
Hydraulic Fracturing ◽  
Numerical Investigation ◽  
Low Permeability ◽  
Low Permeability Reservoir

Success Story of Optimizing Hydraulic Fracturing Design at Alpha Low-Permeability Reservoir

2021 ◽  
Author(s):  
Mario Hadinata Prasetio ◽  
Hanny Anggraini ◽  
Hendro Tjahjono ◽  
Aditya Bintang Pramadana ◽  
Aulia Akbari ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
History Matching ◽  
Initial Period ◽  
Earth Model ◽  
Low Permeability ◽  
Stress Profile ◽  
Reservoir Pressure ◽  
Fracturing Fluid ◽  
Fracture Closure

Abstract This paper describes the evolution of the hydraulic fracturing approach and design in the Alpha reservoir over the past years. Alpha reservoir in XYZ field is a laminated sandstone reservoir with low permeability in the range of 20 to 140 md at a depth of approximately 4,000 to 4,500 ft true vertical depth (TVD). XYZ field is located in Rokan block, Riau, Central Sumatra region. Due to Alpha reservoir's nature, producing from this reservoir commercially requires stimulation. Hydraulic fracturing has been applied as the selected stimulation method to increase productivity from this reservoir. However, several challenges were recognized during the initial period, such as depleted reservoir pressure, indication of fracture height growth, and low to medium Young's modulus, which leads to few screened-out cases as well as low production gain after the fracturing treatment. The fracturing job in Alpha reservoir has been applied since 2002. However, pressure depletion was observed through this time until waterflood optimization started in May 2018 by converting commingled injection to injection dedicated to the Alpha reservoir. The pressure responded and increased from 350 psi to approximately 800 psi. Hence this reservoir still cannot be produced in single completion without the hydraulic fracturing job due to laminated reservoir and low-permeability character. A detailed look at the mechanical earth model (MEM) was done to revise the elastic properties and stress profile considering reservoir pressure change. The revised model was later used as an input for fracture geometry simulation. Calibration injection tests were performed and analyzed prior to the main fracturing treatments to determine fracture closure pressure and leakoff characteristics, which led to fracturing fluid efficiency. Results of these tests were used in job modifications regarding pad percentage, fracturing fluid rheology, proppant volume, and proppant concentration. Pressure history matching both after fracturing and in real time as well as the temperature log were used to validate the MEM and fracture geometries. Each change, approach, and impact were documented and statistically analyzed to determine a generic trend and design envelope for the Alpha reservoir. Between 2019 and 2020, nine wells were stimulated that specifically targeted the Alpha reservoir, with continuous improvement in fracturing design and geomechanics properties with each well. After fracturing, the 30-day oil recovery was superior, higher than previous fractured wells, reaching more than 255 BFPD on average. The successful development of the Alpha reservoir with hydraulic fracturing led to further milestones to maximize oil recovery in XYZ field.

Experience in Optimizing the Location and Parameters of Multistage Hydraulic Fractures for a Multilateral Well Based on Reservoir Simulation

2021 ◽  
Author(s):  
Vil Syrtlanov ◽  
Yury Golovatskiy ◽  
Konstantin Chistikov ◽  
Dmitriy Bormashov
Keyword(s):  
Hydraulic Fracturing ◽  
Reservoir Simulation ◽  
Optimal Placement ◽  
Hydraulic Fractures ◽  
Low Permeability ◽  
Advantages And Disadvantages ◽  
Modeling Methods ◽  
Multistage Hydraulic Fracturing ◽  
Determination Of Parameters

Abstract This work presents the approaches used for the optimal placement and determination of parameters of hydraulic fractures in horizontal and multilateral wells in a low-permeability reservoir using various methods, including 3D modeling. The results of the production rate of a multilateral dualwellbore well are analyzed after the actual hydraulic fracturing performed on the basis of calculations. The advantages and disadvantages of modeling methods are evaluated, recommendations are given to improve the reliability of calculations for models with hydraulic fracturing (HF)/ multistage hydraulic fracturing (MHF).

Role of fracture opening in triggering microseismicity observed during hydraulic fracturing

Geophysics ◽  
2019 ◽  
Vol 84 (3) ◽  
pp. KS105-KS118 ◽  
Author(s):  
Himanshu Barthwal ◽  
Mirko van der Baan
Keyword(s):  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Material Balance ◽  
Crack Tip ◽  
Hydrocarbon Reservoirs ◽  
Fluid Injection ◽  
Low Permeability ◽  
Stress Shadow ◽  
Pressure Diffusion ◽  
Microseismic Events

Hydraulic fracturing in low-permeability hydrocarbon reservoirs creates/reactivates a fracture network leading to microseismic events. We have developed a simplified model of the evolution of the microseismic cloud based on the opening of a planar fracture cavity and its effect on elastic stresses and pore pressure diffusion during fluid injection in hydraulic fracturing treatments. Using a material balance equation, we compute the crack tip propagation over time assuming that the hydraulic fracture is shaped as a single penny-shaped cavity. Results indicate that in low-permeability formations, the crack tip propagates much faster than the pore pressure diffusion front thereby triggering the microseismic events farthest from the injection domain at any given time during fluid injection. We use the crack tip propagation to explain the triggering front observed in distance versus time plots of published microseismic data examples from hydraulic fracturing treatments of low-permeability hydrocarbon reservoirs. We conclude that attributing the location of the microseismic triggering front purely to pore pressure diffusion from the injection point may lead to incorrect estimates of the hydraulic diffusivity by multiple orders of magnitude for low-permeability formations. Moreover, the opening of the fracture cavity creates stress shadow zones perpendicular to the principal fracture walls in which microseismic triggering due to the elastic stress perturbations is suppressed. Microseismic triggering in this stress shadow region may be attributed mainly to pore pressure diffusion. We use the width, instead of the longest size, of the microseismic cloud to obtain an enhanced diffusivity measure, which may be useful for subsequent production simulations.

Permeability Improvement Technology of Directional Hydraulic Fracturing in Low Permeability

2014 ◽  
Vol 599-601 ◽  
pp. 385-390 ◽  
Author(s):  
Xue Xi Chen ◽  
Rui Qing Bi ◽  
Wen Guang Jin ◽  
Yong Xu
Keyword(s):  
Stress Concentration ◽  
Hydraulic Fracturing ◽  
Maximum Concentration ◽  
Local Stress ◽  
Field Application ◽  
Low Permeability ◽  
Pressure Relief ◽  
Local Stress Concentration ◽  
Directional Hydraulic Fracturing ◽  
Better Than

According to the conventional fracturing could easily lead to the local stress concentration of coal, the effect of pressure relief and permeability improvement is not ideal. The mechanism of directional hydraulic fracturing is analyzed and the parameters such as the layout of directional hole, the fracturing hole sealing, the minimum cracking pressure are discussed, then the field application tests are carried out. The results show that the directional hydraulic fracturing effect is better than that of ordinary fracturing hole and the maximum concentration and the average drainage scalar is respectively 3.75 times and 4 times of the ordinary hole pumping gas fracturing effects. The effect of permeability improvement is remarkable.

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