Proppant Hydraulic Fracturing in Low Permeability and Low Acid-Soluble Carbonate Reservoir: A Case History

2010 ◽  
Author(s):  
Silvie Pujiastuti ◽  
Elisa Wijayanti ◽  
Hestu Sapto Nugroho ◽  
Noviadi Istono ◽  
Rio Wijaya ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Case History ◽  
Carbonate Reservoir ◽  
Low Permeability ◽  
Soluble Carbonate

scholarly journals Evaluation And Optimization Production Of Low Permeability Carbonate Reservoir By Hydraulic Fracturing In “Jaso Field”

2021 ◽  
Vol 2 (1) ◽  
pp. 11
Author(s):  
Jakfar Sodi ◽  
Dyah Rini Ratnaningsih ◽  
Dedy Kristanto
Keyword(s):  
Hydraulic Fracturing ◽  
Carbonate Reservoir ◽  
Oil Field ◽  
Carbonate Reservoirs ◽  
Low Permeability ◽  
Solubility Test ◽  
Reservoir Permeability ◽  
Special Cases ◽  
Made In

“Jaso field” is located the South Sumatra basin, Indonesia. The lithology of this field is dominated by limestone / carbonate reservoirs with varying permeability (low / tight to high / porous). Acid Fracturing stimulation has been applied to develop this field, because in ideal conditions (with the solubility test between acid and formation > 80%) wormholes will be made in the formation to increase reservoir conductivity and productivity. However, in the Jaso oil field, in some special cases, acid injection did not provide satisfactory results for increasing well conductivity and productivity.In this thesis, we conduct research and evaluation of wells in Jaso field. For example: JS-28, JS-11 and JS-40 are oil wells in the Jaso field with low / narrow reservoir permeability and production rates. Stimulation has been carried out in the JS-28 well, but the results are still below the acid expectation even though the intermediate solubility test (solubility test) is more than 88%.Hydraulic Fracturing with the sandfracturing method (injecting sand proppant with high pressure and exceeding the gradient fracture) has been successfully applied to three wells in the Jaso Field by increasing the oil production rate by more than 100 bopd per well. With this case study, we find that the application of hydraulic fracturing (sandfracturing) with thrusters is not limited to sandstone / sandstone reservoirs, but that this method can be successfully applied to increase the conductivity and productivity of carbonate reservoirs (in special cases) taking into account several parameters of integrity. reservoir wells and characteristics.

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).

Injectivity and Propagation of Sulfonated Acrylamide-Based Copolymers in Low Permeability Carbonate Reservoir Cores in Harsh Salinity and Temperature Conditions : Challenges and Learnings from a Middle East Onshore Case Study

2021 ◽  
Author(s):  
Nicolas Gaillard ◽  
Matthieu Olivaud ◽  
Alain Zaitoun ◽  
Mahmoud Ould-Metidji ◽  
Guillaume Dupuis ◽  
...  
Keyword(s):  
Middle East ◽  
Polymer Solutions ◽  
Carbonate Reservoir ◽  
Core Material ◽  
Low Permeability ◽  
The Core ◽  
Reservoir Conditions ◽  
Carbonate Cores ◽  
The Impact ◽  
Mobility Reduction

Abstract Polymer flooding is one of the most mature EOR technology applied successfully in a broad range of reservoir conditions. The last developments made in polymer chemistries allowed pushing the boundaries of applicability towards higher temperature and salinity carbonate reservoirs. Specifically designed sulfonated acrylamide-based copolymers (SPAM) have been proven to be stable for more than one year at 120°C and are the best candidates to comply with Middle East carbonate reservoir conditions. Numerous studies have shown good injectivity and propagation properties of SPAM in carbonate cores with permeabilities ranging from 70 to 150 mD in presence of oil. This study aims at providing new insights on the propagation of SPAM in carbonate reservoir cores having permeabilities ranging between 10 and 40 mD. Polymer screening was performed in the conditions of ADNOC onshore carbonate reservoir using a 260 g/L TDS synthetic formation brine together with oil and core material from the reservoir. All the experiments were performed at residual oil saturation (Sor). The experimental approach aimed at reproducing the transport of the polymer entering the reservoir from the sand face up to a certain depth. Three reservoir coreflood experiments were performed in series at increasing temperatures and decreasing rates to mimic the progression of the polymer in the reservoir with a radial velocity profile. A polymer solution at 2000 ppm was injected in the first core at 100 mL/h and 40°C. Effluents were collected and injected in the second core at 20 mL/h and 70°C. Effluents were collected again and injected in the third core at 4 mL/h and 120°C. A further innovative approach using reservoir minicores (6 mm length disks) was also implemented to screen the impact of different parameters such as Sor, molecular weight and prefiltration step on the injectivity of the polymer solutions. According to minicores data, shearing of the polymer should help to ensure good propagation and avoid pressure build-up at the core inlet. This result was confirmed through an injection in a larger core at Sor and at 120°C. When comparing the injection of sheared and unsheared polymer at the same concentration, core inlet impairment was suppressed with the sheared polymer and the same range of mobility reduction (Rm) was achieved in the internal section of the core although viscosity was lower for the sheared polymer. Such result indicates that shearing is an efficient way to improve injectivity while maximizing the mobility reduction by suppressing the loss of product by filtration/retention at the core inlet. This paper gives new insights concerning SPAM rheology in low permeability carbonate cores. Additionally, it provides an innovative and easier approach for screening polymer solutions to anticipate their propagation in more advanced coreflooding experiments.

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