Synthesis and modification of graphene nanofluid surface in terms of wettability alteration of carbonate reservoir rock

2020 ◽  
pp. 1-15 ◽  
Author(s):  
Ehsan Jafarbeigi ◽  
Ehsan Kamari ◽  
Farhad Salimi ◽  
Akbar Mohammadidoust
Keyword(s):  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Wettability Alteration

Artificial Intelligence Used to Evaluate 23 Single-Well Surfactant-Soak Treatments

2006 ◽  
Vol 9 (03) ◽  
pp. 209-216 ◽  
Author(s):  
William W. Weiss ◽  
Xina Xie ◽  
Jason Weiss ◽  
Vishu Subramanian ◽  
Archie R. Taylor ◽  
...  
Keyword(s):  
Artificial Intelligence ◽  
Field Test ◽  
Water Saturation ◽  
Field Tests ◽  
Recovery Process ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Single Well ◽  
Phosphoria Formation

Summary Following a series of laboratory imbibition-cell experiments, field tests were conducted to determine the effectiveness of surfactant-soak treatments as a single-well enhanced-oil-recovery (EOR) technique. The tests were conducted in the dolomite interval of the Phosphoria formation. Artificial intelligence was applied to analyze the mixed test results. The analysis suggested that the gamma ray log can be used to predict results and that a minimum amount of surfactant is required to improve production. Introduction Water imbibition as a recovery process was tested in the Spraberry field during the 1950s (Elkins and Skov 1962, 1963). This early work was followed by a test of the process in Cottonwood Creek field during the 1960s (Willingham and McCaleb 1967). Around the time of these field tests, a patent was issued (Graham et al. 1957) that suggested surfactants could enhance the imbibition recovery process. A later patent (Stone et al. 1970) implied that a Spraberry field test was designed, but results were not reported. Forty years later, researchers (Spindler et al. 2000; Standnes and Austad 2000; Chen et al. 2000) returned to the subject of wettability alteration. One description of a field test of the surfactant-soak process has been published (Chen et al. 2000). A great deal of effort was expended during the 1970s and 1980s in designing systems and field testing surfactant fluids with ultralow interfacial tensions (IFTs) as a flooding EOR process. Maintaining the integrity of the chemical slug from the injection well to the producing wells was fraught with problems. However, slug-integrity problems are diminished in single-well EOR applications. Recent laboratory work focused on the easily performed and interpreted imbibition-cell experiments. These experiments (with and without surfactants) and the reported success of pressure pulsing at Cottonwood Creek prompted further laboratory testing with reservoir rock and fluids (Xie 2002; Xie et al. 2004). This recent work indicated that a nonionic surfactant could substantially increase recovery from Phosphoria wells in the Cottonwood Creek field. The shallow-shelf carbonate reservoir is characterized as a steeply dipping, algal reef of the Phosphoria formation producing sour, 27°API, black oil from a dolomitized interval. Thickness of the dolomite varies from 20 to 100 ft. The average porosity is ~10% with ~1.0 md matrix permeability. The connate-water saturation is ~10%. Pan American Petroleum reported the low-pressure and low-temperature reservoir to be naturally fractured and oil-wet (Willingham and McCaleb 1967). Their description was based on laboratory core studies. Tests performed in the 1990s generated U.S. Bureau of Mines (USBM) wettability values of -0.1, -0.12, -0.18, and -0.26. The Cottonwood Creek field is located in the Bighorn basin of Wyoming, as shown in Fig. 1, and is operated by Continental Resources Inc.

scholarly journals Production improvement in gas condensate reservoirs by wettability alteration, using superamphiphobic titanium oxide nanofluid

2018 ◽  
Vol 73 ◽  
pp. 46 ◽  
Author(s):  
Pouriya Esmaeilzadeh ◽  
Mohammad Taghi Sadeghi ◽  
Alireza Bahramian
Keyword(s):  
Liquid Phase ◽  
Relative Permeability ◽  
Core Sample ◽  
Carbonate Reservoir ◽  
Gas Condensate ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Energy Materials ◽  
Gas Condensate Reservoirs ◽  
Production Improvement

Many gas condensate reservoirs suffer a loss in productivity owing to accumulation of liquid in near-wellbore region. Wettability alteration of reservoir rock from liquid-wetting to gas-wetting appears to be a promising technique for elimination of the condensate blockage. In this paper, we report use of a superamphiphobic nanofluid containing TiO2 nanoparticles and low surface energy materials as polytetrafluoroethylene and trichloro(1H,1H,2H,2H-perfluorooctyl)silane to change the wettability of the carbonate reservoir rock to ultra gas-wetting. The utilization of nanofluid in the wettability alteration of carbonate rocks to gas-wetting in core scale has not been reported already and is still an ongoing issue. Contact angle measurements was conducted to investigate the wettability of carbonate core plugs in presence of nanofluid. It was found that the novel formulated nanofluid used in this work can remarkably change the wettability of the rock from both strongly water- and oil-wetting to highly gas-wetting condition. The adsorption of nanoparticles on the rock and formation of nano/submicron surface roughness was verified by Scanning Electron Microscope (SEM) and Stylus Profilometer (SP) analyses. Using free imbibition test, we showed that the nanofluid can imbibe interestingly into the core sample, resulting in notable ultimate gas-condensate liquid recovery. Moreover, we studied the effect of nanofluid on relative permeability and recovery performance of gas/water and gas/oil systems for a carbonate core. The result of coreflooding tests demonstrates that the relative permeability of both gas and liquid phase increased significantly as well as the liquid phase recovery enhanced greatly after the wettability alteration to gas-wetting.

scholarly journals Wettability alteration and enhanced gas condensate recovery by treatment of carbonate reservoir rock using supercritical R134A and R404A gases

2020 ◽  
Vol 10 (8) ◽  
pp. 3751-3766 ◽  
Author(s):  
Iman Nowrouzi ◽  
Abbas Khaksar Manshad ◽  
Amir H. Mohammadi
Keyword(s):  
Contact Angle ◽  
Pressure Drop ◽  
Cross Sections ◽  
Carbonate Reservoir ◽  
Gas Condensate ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Thin Sections ◽  
Coated Nanoparticles ◽  
Condensate Reservoir

Abstract The pressure drop around the well in the production from a gas condensate reservoir causes the formation of condensate in the area before it reaches the well and surface space. This condensate and occasionally water in the porous medium can block the well and create an additional pressure drop. Studies show that the chemical treatment of this area eliminates the problem by altering the reservoir rock wettability toward a moderate and strong gasphilicity. For this purpose, fluoropolymers-, fluorosurfactants-, and fluorochemicals-coated nanoparticles can be used. In this work, we have studied two types of fluoride gas namely R134A and R404A, which are widely used in refrigeration industry as refrigerant gases, perfumery, and industrial detergents. The basis of this study was the aging of rock samples in thin sections and plugs in these two gases at different pressures above the critical pressures of them at 70 °C at different times and then conducting the contact angle experiments by placing the drop of water and condensate on the cross sections and then performing imbibition tests using plugs. The results show that in addition to the efficiency of both gases in wettability alteration to gasphilic, the gasphilic intensity obtained at constant temperature depends on the pressure and the aging time of the samples.

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).

Utilizing NMR Workflow to Optimize Power Water Injector Placement in the Presence of Tar Barriers

2021 ◽  
Author(s):  
Gabor Hursan ◽  
Mohammed Sahhaf ◽  
Wala’a Amairi
Keyword(s):  
Spectral Analysis ◽  
Pore Size ◽  
Real Time ◽  
Total Porosity ◽  
Carbonate Reservoir ◽  
Wettability Alteration ◽  
Well Placement ◽  
Carbonate Formation ◽  
Fluid Saturation ◽  
Rock Quality

Abstract The objective of this work is to optimize the placement of horizontal power water injector (PWI) wells in stratified heterogeneous carbonate reservoir with tar barriers. The key to successful reservoir navigation is a reliable real-time petrophysical analysis that resolves rock quality variations and differentiates tar barriers from lighter hydrocarbon intervals. An integrated workflow has been generated based on logging-while drilling (LWD) triple combo and Nuclear Magnetic Resonance (NMR) logging data for fluid identification, tar characterization and permeability prediction. The workflow has three steps; it starts with the determination of total porosity using density and neutron logs, the calculation of water-filled porosity from resistivity measurements and an additional partitioning of porosity into bound and free fluid volumes using the NMR data. Second, the total and water-filled porosity, the NMR bound fluid and NMR total porosity are used as inputs in a hydrocarbon compositional and viscosity analysis of hydrocarbon-bearing zones for the recognition of tar-bearing and lighter hydrocarbon intervals. Third, in the lighter hydrocarbon intervals, NMR logs are further analyzed using a multi-cutoff spectral analysis to identify microporous and macroporous zones and to calculate the NMR mobility index. The ideal geosteering targets are highly macroporous rocks containing no heavy hydrocarbons. In horizontal wells, the method is validated using formation pressure while drilling (FPWD) measurements. The procedure has been utilized in several wells. The original well path of the first injector was planned to maintain a safe distance above an anticipated tar-bearing zone. Utilizing the new real-time viscosity evaluation, the well was steered closer to the tar zone several feet below the original plan, setting an improved well placement protocol for subsequent injectors. In the water- or lighter hydrocarbon-bearing zones, spectral analysis of NMR logs clearly accentuated micro- and macroporous carbonate intervals. The correlation between pore size and rock quality has been corroborated by FPWD mobility measurements. In one well, an extremely slow NMR relaxation may indicate wettability alteration in a macroporous interval. An integrated real-time evaluation of porosity, fluid saturation, hydrocarbon viscosity and pore size has enhanced well placement in a heterogeneous carbonate formation where tar barriers are also present. The approach increased well performance and substantially improved reservoir understanding.

Needles in the Pay Stack ADNOC Exploring Tight-Oil Rock, Triples Production In First Pilot

2021 ◽  
Vol 73 (01) ◽  
pp. 20-22
Author(s):  
Trent Jacobs
Keyword(s):  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Abu Dhabi ◽  
Data Set ◽  
Slowing Down ◽  
Tight Carbonate ◽  
Potential Impact ◽  
Carbonate Formations ◽  
Oil Company ◽  
Term Data

In the midst of an industry downturn last year, the Abu Dhabi National Oil Company (ADNOC) reached a new oil production ceiling of 4 million B/D. The UAE’s largest producer has no intentions of slowing down. By decade’s end, ADNOC expects to have raised its maximum daily output by another million barrels. To cross that milestone, the company has set its sights on mastering the tight, thin, and unconventional formations that dot the UAE’s subsurface landscape. One of the places where such developments are hoped to unfold soon is known as Field Q. Found in southeastern Abu Dhabi, Field Q sits above a tight carbonate reservoir that holds an estimated 600 million bbl of oil. But with a permeability ranging from 1 to 3 millidarcy and poor vertical communication, the reservoir and its barrels have proven difficult to cultivate economically - until recently. ADNOC has published new details of its first onshore pilot of a “fishbone stimulation” that involved using more than a hundred hollow needles to pierce as far as 40 ft into the reservoir rock. The additional drainage netted by the fishbone needles boosted production threefold in the test well, as compared with its traditionally completed neighbors on the same pad. ADNOC ran the pilot in the summer of 2019 and by the end of the year saw enough production data to launch a wider 10-well pilot that remains underway. Based on a longer-term data set from these wells, the company will decide whether to leap into a fieldwide deployment of the niche completions technology. In the meantime, the petrotechnical team in charge of the test projects have issued roundly positive reviews of the fishbone technique in two recently presented technical papers (SPE 202636; SPE 203086) from the Abu Dhabi International Petroleum Exhibition & Conference (ADIPEC). “There is a chance that the fishbone-stimulated wells can avoid the drilling of multiple wells targeting different sublayers in the same zone,” said Rama Rao Rachapudi, listing one of several of the technology’s advantages over other approaches that were considered. The senior petroleum engineer with ADNOC, who is one of several authors of the papers that cover both the drilling and completions aspects of the pilot, shared during ADIPEC that his onshore team found motivation to test the technology after bringing in a batch of dis-mal appraisal wells. The fishbone system, also known as multilateral jetting stimulation technology, has been a specialized application ever since it was introduced just over a decade ago. Underscoring the potential impact of the current round of pilots on the technology’s adoption rate, ADNOC noted there were only around 30 worldwide fishbone deployments prior to this project. Most of those have been in the Middle East’s naturally fractured and layered carbonate formations - just like those of Field Q.

Sign in / Sign up

Export Citation Format

Share Document