An Improved Method for Measuring Fluid Loss at Simulated Fracture Conditions

1985 ◽  
Vol 25 (04) ◽  
pp. 482-490 ◽  
Author(s):  
Robert Ray McDaniel ◽  
Asoke Kumar Deysarkar ◽  
Michael Joseph Callanan ◽  
Charles A. Kohlhaas
Keyword(s):  
Fluid Flow ◽  
Shear Rate ◽  
Filter Paper ◽  
Filter Cake ◽  
Fluid Loss ◽  
Test Results ◽  
Test Apparatus ◽  
Fracturing Fluid ◽  
The Core ◽  
Static Core

Abstract A test apparatus is designed to carry out dynamic and static fluid-loss tests of fracturing fluids. This test apparatus simulates the pressure difference, temperature, rate of shear, duration of shear, and fluid-flow pattern expected under fracture conditions. For a typical crosslinked fracturing fluid, experimental results indicate that fluid loss values can be a function of temperature, pressure differential, rate of shear, and degree of non-Newtonian behavior of the fracturing fluid. A mathematical development demonstrates that the fracturing-fluid coefficient and filter-cake coefficient can be obtained only if the individual pressure drops can be measured during a typical fluid-loss test. Introduction In a hydraulic fracturing treatment, the development of fracture length and width is strongly dependent on a number of key fluid and formation parameters. One of the most important of these parameters is the rate at which the fracturing fluid leaks, off into the created fracture faces. This parameter, identified as fluid loss, also influences the time required for the fracture to heal after the stimulation treatment has been terminated. This in turn will influence the final distribution of proppant in the fracture and will dictate when the well can be reopened and the cleanup process started. Historically, tests to measure fluid loss have been carried out primarily under what is characterized as static conditions. In such tests, the fracturing fluid is forced through filter paper or through a thin core wafer under a pressure gradient, and the flow rate at the effluent side is determined. Of course, the use of filter paper cannot account for reservoir formation permeability and porosity; therefore, the fluid-loss characteristics derived from such tests should be viewed as only gross approximations. The static core-wafer test on the other hand, reflects to some extent the interaction of the formation and fracturing-fluid properties. However, one important fluid property is altogether ignored in such static core-wafer tests. This is the effect of shear rate in the fracture on the rheology (viscosity) of fracturing fluid and subsequent effects of viscosity on the fluid loss through the formation rock. In the past, several attempts were made to overcome the drawbacks of static core-wafer tests by adopting dynamic fluid-loss tests. Although these dynamic tests were a definite improvement over the static versions, each had drawbacks or limitations that could influence test results. In some of the studies, the shearing area was annular rather than planar as encountered in the fracture. In other cases, the fluid being tested did not experience a representative shear rate for a sufficiently long period of time. An additional problem arose because most studies were performed at moderate differential pressures and temperatures. The final drawback in several of the studies was that the fluid flow and leakoff patterns did not realistically simulate those occurring in the field. In the first part of this paper, we emphasize the design of a dynamic fluid-loss test apparatus that possesses none of these drawbacks. In the second part of the paper, test results with this apparatus are presented for three different fluid systems. These systems areglycerol, a non-wall-building Newtonian fluid,a polymer gel solution that is slightly wall-building and non-Newtonian, anda crosslinked fracturing system that is highly non-Newtonian in nature and possesses the ability to build a wall (filter cake) on the fracture face (see Table 1). The fluids were subjected to both static and dynamic test procedures. In the third part of the paper, results of experiments carried out with crosslinked fracturing fluid for different core lengths, pressure differences, temperatures, and shear rates are compared and the significance of the difference of fluid loss is emphasized. Experimental Equipment and Procedure The major components of the experimental apparatus shown in Fig. 1 are a fluid-loss cell, circulation pump, heat exchanger, system pressurization accumulators, and a fluid-loss recording device. The construction material throughout most of the system is 316 stainless steel. The fluid loss is measured through a cylindrical core sample, 1.5 in. [3.81 cm] in diameter, mounted in the fluid-loss cell. Heat-shrink tubing is fitted around the circumference of the core and a confining pressure is maintained to prevent channeling. Fracturing fluid is circulated through a rectangular channel across one end of the core. SPEJ P. 482^

Fracturing Fluids: Fluid-Loss Measurements Under Dynamic Conditions

1985 ◽  
Vol 25 (05) ◽  
pp. 629-636 ◽  
Author(s):  
L.P. Roodhart
Keyword(s):  
Shear Rate ◽  
Filter Cake ◽  
Fluid Loss ◽  
Square Root ◽  
Fracturing Fluid ◽  
Rock Permeability ◽  
Static Test ◽  
The Third ◽  
Fracturing Fluids ◽  
Third Stage

Abstract When filter-cake-building additives are used in fracturing fluids, the commonly applied static, 30-minute API filtration test is unsatisfactory, because in a dynamic situation (like fracturing) the formation of a thick filter cake will be inhibited by the shearing forces of the fracturing fluid. A dynamic, filter-cake-controlled, leakoff coefficient that is dependent on the shear rate and shear stress at the fracture face is, therefore, introduced. A test apparatus has been constructed in which the fluid leakoff is measured under conditions of temperature, rate of shear, duration of shear, and fluid-flow pattern as encountered under fracturing conditions. The effects of rock permeability, shear rate, and differential pressure on the permeability, shear rate, and differential pressure on the dynamic leakoff coefficient are presented for various, commonly used fracturing-fluid/fluid-loss-additive combinations. Introduction An important parameter in hydraulic fracturing design is the rate at which the fracturing fluid leaks into the formation. This parameter, known as fluid loss, not only determines the development of fracture length and width, but also governs the time required for a fracture to heal after the stimulation treatment has been terminated. The standard leakoff test is a static test, in which the effect of shear rate in the fracture on the viscosity of the fracturing fluid and on the filter-cake buildup is ignored. Dynamic vs. Static Tests The three stages in filter-cake buildup arespurt loss during initiation of the filter cake,buildup of filtercake thickness, during which time leakoff is proportional to the square root of time, andlimitation of filter-cake growth by erosion. In the standard API leakoff test, 1 the fracturing fluid, with or without leakoff additives, is forced through a disk of core material under a pressure differential of 1000 psi [7 MPa), and the flow rate of the filtrate is determined. In such a static test, the third stage-erosion of the filter cake-is absent. In a dynamic situation there is an equilibrium whereby flow along the filter cake limits the filter-cake thickness, and the leakoff rate becomes constant. The duration of each of these stages depends on the type of fluid, the type of additive, the rock permeability, and the test conditions. The differences between dynamic and static filtration tests are shown in Fig. 1, where the cumulative filtrate volume (measured in some experiments with the dynamic fluid-loss apparatus described below) is expressed as a function of time (Fig. la) and as a function of the square root of time (Fig. ]b), The shear rate at the surface of the disk is either static (O s -1 ), or 109 s -1 or 611 s -1. The curves indicate that the dynamic filtration velocities are higher than those measured in a static test and increase rapidly with increasing shear rate. This is in agreement with the observations made by Hall, who used an axially transfixed cylindrical core sample along which fracturing fluid was pumped, while the filtrate was collected from a bore through the center. Fig. la shows how the lines were drawn to fit the data: Vc = Vsp + A t + Bt, .........................(1) where Vc = cumulative volume per unit area, t = filtration time, Vsp= spurt loss, A = static leakoff component, andB = dynamic leakoff component. In static leakoff theory, B =0 and then A =2Cw, twice the static leakoff coefficient.-3 Each of the terms in Eq. 1 represents one of the stages in the leakoff process-spurt loss, buildup of filter cake, and erosion of filter cake. Analysis of the experimental data shows that the spurt loss, Vsp, and the static leakoff component, A, are independent of the shear rate, but the dynamic component, B, varies strongly with the shear rate (see Table 1). This means that, the higher the shear rate, the more the leakoff process is controlled by the third stage. process is controlled by the third stage. One model commonly used is based solely on square-root-of-time behavior with a constant spurt loss. Fig. 1 shows that little accuracy is lost by describing the leakoff with a single square-root-of-time equation: Vc = VsP + m t,...........................(2) where the dynamic leakoff coefficient. Cw = 1/2m, depends heavily on shear. and the spurt loss remains the same as in Eq. 1 and independent of the shear rate Table 2 shows that the error in C, that arises as a result of measuring under static conditions can be more than 100%. SPEJ P. 629

scholarly journals Experimental Investigation and Performance Evaluation of Modified Viscoelastic Surfactant (VES) as a New Thickening Fracturing Fluid

Polymers ◽  
2020 ◽  
Vol 12 (7) ◽  
pp. 1470
Author(s):  
Z. H. Chieng ◽  
Mysara Eissa Mohyaldinn ◽  
Anas. M. Hassan ◽  
Hans Bruining
Keyword(s):  
Shear Rate ◽  
Hydraulic Fracturing ◽  
Shear Resistance ◽  
Core Flooding ◽  
Single Chain ◽  
Fracturing Fluid ◽  
The Core ◽  
Core Damage ◽  
Fracturing Fluids ◽  
Viscoelastic Surfactant

In hydraulic fracturing, fracturing fluids are used to create fractures in a hydrocarbon reservoir throughout transported proppant into the fractures. The application of many fields proves that conventional fracturing fluid has the disadvantages of residue(s), which causes serious clogging of the reservoir’s formations and, thus, leads to reduce the permeability in these hydrocarbon reservoirs. The development of clean (and cost-effective) fracturing fluid is a main driver of the hydraulic fracturing process. Presently, viscoelastic surfactant (VES)-fluid is one of the most widely used fracturing fluids in the hydraulic fracturing development of unconventional reservoirs, due to its non-residue(s) characteristics. However, conventional single-chain VES-fluid has a low temperature and shear resistance. In this study, two modified VES-fluid are developed as new thickening fracturing fluids, which consist of more single-chain coupled by hydrotropes (i.e., ionic organic salts) through non-covalent interaction. This new development is achieved by the formulation of mixing long chain cationic surfactant cetyltrimethylammonium bromide (CTAB) with organic acids, which are citric acid (CA) and maleic acid (MA) at a molar ratio of (3:1) and (2:1), respectively. As an innovative approach CTAB and CA are combined to obtain a solution (i.e., CTAB-based VES-fluid) with optimal properties for fracturing and this behaviour of the CTAB-based VES-fluid is experimentally corroborated. A rheometer was used to evaluate the visco-elasticity and shear rate & temperature resistance, while sand-carrying suspension capability was investigated by measuring the settling velocity of the transported proppant in the fluid. Moreover, the gel breaking capability was investigated by determining the viscosity of broken VES-fluid after mixing with ethanol, and the degree of core damage (i.e., permeability performance) caused by VES-fluid was evaluated while using core-flooding test. The experimental results show that, at pH-value ( 6.17 ), 30 (mM) VES-fluid (i.e., CTAB-CA) possesses the highest visco-elasticity as the apparent viscosity at zero shear-rate reached nearly to 10 6 (mPa·s). Moreover, the apparent viscosity of the 30 (mM) CTAB-CA VES-fluid remains 60 (mPa·s) at (90 ∘ C) and 170 (s − 1 ) after shearing for 2-h, indicating that CTAB-CA fluid has excellent temperature and shear resistance. Furthermore, excellent sand suspension and gel breaking ability of 30 (mM) CTAB-CA VES-fluid at 90 ( ∘ C) was shown; as the sand suspension velocity is 1.67 (mm/s) and complete gel breaking was achieved within 2 h after mixing with the ethanol at the ratio of 10:1. The core flooding experiments indicate that the core damage rate caused by the CTAB-CA VES-fluid is ( 7.99 % ), which indicate that it does not cause much damage. Based on the experimental results, it is expected that CTAB-CA VES-fluid under high-temperature will make the proposed new VES-fluid an attractive thickening fracturing fluid.

A Comparative Study between p-Aminobenzensulfonate-Phenol-Formaldehyde Condensate and Sulfomethylated Phenolic Resin as Drilling Mud Fluid Loss Reducer

2014 ◽  
Vol 1081 ◽  
pp. 31-37
Author(s):  
Jin Peng Chai ◽  
Zheng Song Qiu
Keyword(s):  
Thermal Stability ◽  
Particle Size ◽  
Filter Cake ◽  
Phenolic Resin ◽  
Phenol Formaldehyde ◽  
Fluid Loss ◽  
Good Property ◽  
Test Results ◽  
Drilling Mud ◽  
Loss Control

The p-aminobenzensulfonate-phenol-formaldehyde (APF) condensate is synthesized and characterized by FTIR and TGA analyses. Its properties as drilling mud fluid loss reducer are studied with respect to fluid loss and particle size distribution. In addition, the effect of salt on properties of APF condensate was discussed. Test results show that the APF condensate not only possesses higher thermal stability than sulfomethylated phenolic resin (SMP), a commercial drilling mud additive, but also achieves good property of fluid loss control by reducing the permeability of filter cake; the fluid-loss controlling properties of APF condensate dropped with the increase of concentrations of NaCl.

Polyelectrolyte Multilayered Nanoparticles as Nanocontainers for Enzyme Breakers During Hydraulic Fracturing Process

2021 ◽  
Author(s):  
Mubarak Muhammad Alhajeri ◽  
Jenn-Tai Liang ◽  
Reza Barati Ghahfarokhi
Keyword(s):  
Controlled Release ◽  
Filter Cake ◽  
Entrapment Efficiency ◽  
High Loading ◽  
Fluid Loss ◽  
Colloidal Structure ◽  
Fracturing Fluid ◽  
Fracture Conductivity ◽  
Polyelectrolyte Solution ◽  
Static Conditions

Abstract In this study, Layer-by-Layer (LbL) assembled polyelectrolyte multilayered nanoparticles were developed as a technique for targeted and controlled release of enzyme breakers. Polyelectrolyte multilayers (PEMs) were assembled by means of alternate electrostatic adsorption of polyanions and polycations using colloidal structure of polyelectrolyte complexes (PECs) as LbL building blocks. High enzyme concentrations were introduced into polyethyleneimine (PEI), a positively charged polyelectrolyte solution, to form an electrostatic PECs with dextran sulfate (DS), a negatively charged polyelectrolyte solution. Under the right concentrations and pH conditions, PEMs were assembled by alternating deposition of PEI with DS solutions at the colloidal structure of PEI-DS complexes. Stability and reproducibility of PEMs were tested over time. This work demonstrates the significance of PEMs as a technique for the targeted and controlled release of enzymes based on their high loading capacity, high capsulation efficiency, and extreme control over enzyme concentration. Entrapment efficiency (EE%) of polyelectrolyte multilayered nanoparticles were evaluated using concentration measurement methods as enzyme viscometric assays. Controlled release of enzyme entrapped within PEMs was sustained over longer time periods (> 18 hours) through reduction in viscosity, and elastic modulus of borate-crosslinked hydroxypropyl guar (HPG). Long-term fracture conductivity tests at 40℃ under closure stresses of 1,000, 2,000, and 4,000 psi revealed high fracture clean-up efficiency for fracturing fluid mixed with enzyme-loaded PEMs nanoparticles. The retained fracture conductivity improvement from 25% to 60% indicates the impact of controlled distribution of nanoparticles in the filter cake and along the entire fracture face as opposed to the randomly dispersed unentrapped enzyme. Retained fracture conductivity was found to be 34% for fluid systems containing conventional enzyme-loaded PECs. Additionally, enzyme-loaded PEMs demonstrated enhanced nanoparticle distribution, high loading and entrapment efficiency, and sustained release of the enzyme. This allows for the addition of higher enzyme concentrations without compromising the fluid properties during a treatment, thereby effectively degrading the concentrated residual gel to a greater extent. Fluid loss properties of polyelectrolyte multilayered nanoparticles were also studied under static conditions using a high-pressure fluid loss cell. A borate-crosslinked HPG mixed with nanoparticles was filtered against core plugs with similar permeabilities. The addition of multilayered nanoparticles into the fracturing fluid was observed to significantly improve the fluid- loss prevention effect. The spurt-loss coefficient values were also determined to cause lower filtrate volume than those with crosslinked base solutions. The PEI-DS complex bridging effects revealed a denser, colored filter cake indicating a relatively homogenous dispersion and properly sized particles in the filter cake.

scholarly journals Post-magmatic fracturing, fluid flow, and vein mineralization in supra-subduction zones: a comparative study on vein calcites from the Troodos ophiolite and the Izu–Bonin forearc and rear arc

2021 ◽  
Vol 110 (2) ◽  
pp. 627-649
Author(s):  
Dennis Quandt ◽  
W. Kurz ◽  
P. Micheuz
Keyword(s):  
Fluid Flow ◽  
Subduction Zones ◽  
Growth Dynamics ◽  
Pillow Lava ◽  
Published Data ◽  
Fracturing Fluid ◽  
Deep Seawater ◽  
Vein Formation ◽  
Mineralization Processes ◽  
Extensional Faulting

AbstractBased on the published data of pillow lava-hosted mineralized veins, this study compares post-magmatic fracturing, fluid flow, and secondary mineralization processes in the Troodos and Izu–Bonin supra-subduction zone (SSZ) and discusses the crucial factors for the development of distinct vein types. Thin section and cathodoluminescence petrography, Raman spectroscopy, fluid inclusion microthermometry, and trace element and isotope (87Sr/86Sr, δ18O, δ13C, Δ47) geochemistry indicate that most veins consist of calcite that precipitated from pristine to slightly modified seawater at temperatures < 50 °C. In response to the mode of fracturing, fluid supply, and mineral growth dynamics, calcites developed distinct blocky (precipitation into fluid-filled fractures), syntaxial (crack and sealing), and antitaxial (diffusion-fed displacive growth) vein microtextures with vein type-specific geochemical signatures. Blocky veins predominate in all study areas, whereas syntaxial veins represent subordinate structures. Antitaxial veins occur in all study areas but are particularly abundant in the Izu–Bonin rear arc where the local geological setting was conducive of antitaxial veining. The temporal framework of major calcite veining coincides with the onset of extensional faulting in the respective areas and points to a tectonic control on veining. Thus, major calcite veining in the Troodos SSZ began contemporaneously with volcanic activity and extensional faulting and completed within ~ 10–20 Myr. This enabled deep seawater downflow and hydrothermal fluid upflow. In the Izu–Bonin forearc, reliable ages of vein calcites point to vein formation > 15 Myr after subduction initiation. Therefore, high-T mineralization (calcite, quartz, analcime) up to 230 °C is restricted to the Troodos SSZ.

Rheological Characteristics of Viscoelastic Surfactant Fluid Mixed With Silica Nanoparticles

2013 ◽  
Author(s):  
Yueqiong Wu ◽  
Zhongyang Luo ◽  
Hong Yin ◽  
Tao Wang
Keyword(s):  
High Temperature ◽  
Shear Rate ◽  
Volume Fraction ◽  
Sio2 Nanoparticles ◽  
Fluid Loss ◽  
Rheological Characteristics ◽  
High Shear ◽  
Fracturing Process ◽  
Viscoelastic Surfactant ◽  
Rheological Performance

Since the surfactant can form rod-like micelles or even cross-link structures, viscoelastic surfactant (VES) fluid has unique rheological characteristics. The demerits of VES fluids have been proven after being applied as the fracturing fluid for several years. However, the fluid has high fluid loss and a low viscosity at high temperature, which limits the application to hydraulic fracturing. This paper focuses on the VES fluid mixed with nanoparticles which should be an effective way to maintain the viscosity at high temperature and high shear rate. The experiments were based on preparation of uniform and stable nanocolloids, which utilize Microfluidizer high shear fluid processor. Dynamic light scattering and microscopic methods are employed to investigate the stability and micro-structure of the VES fluid. The effects of temperature, shear rate and volume fraction of the nanoparticles on rheology of VES were studied. The SiO2 nanoparticles could significantly improve the rheological performance of VES fluid, although the rheological performance at the temperature over 90 °C needs to be enhanced. The mechanisms of interactions between nanoparticles and micelles are also discussed later in the paper. At the end, the potential of VES fluid mixed with nanoparticles during application in fracturing process was discussed.

scholarly journals Behaviour of eccentrically inclined loaded rectangular foundation on reinforced sand

2021 ◽  
Vol 0 (0) ◽  
Author(s):  
Sujata Gupta ◽  
Anupam Mital
Keyword(s):  
Bearing Capacity ◽  
Loading Conditions ◽  
Test Results ◽  
Bearing Capacity Ratio ◽  
Reinforced Sand ◽  
The Core ◽  
Capacity Ratio ◽  
Core Boundary ◽  
Rectangular Foundation ◽  
Increasing Load

Abstract This study presents the behaviour of model footing resting over unreinforced and reinforced sand bed under different loading conditions carried out experimentally. The parameters investigated in this study includes the number of reinforced layers (N = 0, 1, 2, 3, 4), embedment ratio (Df /B = 0, 0.5, 1.0), eccentric and inclined ratio (e/L, e/B = 0, 0.05, 0.10, 0.15) and (a = 0°, 7°, 14°). The test sand was reinforced with bi-axial geogrid (Bx20/20). The test results show that the ultimate bearing capacities decrease with axial eccentricity and inclination of applied loads. The test results also show that the depth of model footing increase zero to B (B = width of model footing), an increase of ultimate bearing capacity (UBC) approximated at 93%. Similarly, the multi-layered geogrid reinforced sand (N = 0 to 4) increases the UBC by about 75%. The bearing capacity ratio (BCR) of the model footing increases with an increasing load eccentricity to the core boundary of footing; if the load eccentricities increase continuity, the BCR decreases. The tilt of the model footing is increased by increasing the eccentricity and decreases with increasing the number of reinforcing layers.

scholarly journals A new slick water system for hydraulic fracturing in tight reservoir to enhance imbibition oil recovery

2021 ◽  
Vol 303 ◽  
pp. 01001
Author(s):  
Yu Haiyang ◽  
Ji Wenjuan ◽  
Luo Cheng ◽  
Lu Junkai ◽  
Yan Fei ◽  
...  
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
Water System ◽  
Natural Fracture ◽  
Fracturing Fluid ◽  
The Core ◽  
Ultralow Permeability

In order to give full play to the role of imbibition of capillary force and enhance oil recovery of ultralow permeability sandstone reservoir after hydraulic fracturing, the mixed water fracture technology based on functional slick water is described and successfully applied to several wells in oilfield. The core of the technology is determination of influence factors of imbibition oil recovery, the development of new functional slick water system and optimization of volume fracturing parameters. The imbibition results show that it is significant effect of interfacial tension, wetting on imbibition oil recovery. The interfacial tension decreases by an order of magnitude, the imbibition oil recovery reduces by more than 10%. The imbibition oil recovery increases with the contact angle decreasing. The emulsifying ability has no obvious effect on imbibition oil recovery. The functional slick water system considering imbibition is developed based on the solution rheology and polymer chemistry. The system has introduced the active group and temperature resistant group into the polymer molecules. The molecular weight is controlled in 1.5 million. The viscosity is greater than 2mPa·s after shearing 2h under 170s-1 and 100℃. The interfacial tension could decrease to 10-2mN/m. The contact angle decreased from 58° to 22° and the core damage rate is less than 12%. The imbibition oil recovery could reach to 43%. The fracturing process includes slick water stage and linear gel stage. 10% 100 mesh ceramists and 8% temporary plugging agents are carried into the formation by functional slick water. 40-70 mesh ceramists are carried by linear gel. The liquid volume ratio is about 4:1 and the displacement is controlled at 10-12m3/min. The sand content and fracturing fluid volumes of single stage are 80m3 and 2500 m3 respectively. Compared with conventional fracturing, due to imbibition oil recovery, there is only 25% of the fracturing fluid flowback rate when the crude oil flew out. When the oil well is in normal production, about 50% of the fracturing fluid is not returned. It is useful to maintain the formation energy and slow down the production decline. The average cumulative production of vertical wells is greater than 2800t, and the effective period is more than 2 years. This technology overcoming the problem of high horizontal stress difference and lack of natural fracture has been successfully applied in Jidong Oilfield ultralow permeability reservoir. The successful application of this technology not only helps to promote the effective use of ultralow permeability reservoirs, but also helps to further clarify the role of imbibition recovery, energy storage and oil-water replacement mechanism.

Laboratory Investigation of Permeability Impairment Caused by Asphaltene Precipitation during Screening for Gas-Injection Enhanced Oil Recovery and Pressure Change in a Major Gulf of Mexico Field

SPE Journal ◽  
2021 ◽  
pp. 1-21
Author(s):  
M. R. Fassihi ◽  
E. Turek ◽  
M. Matt Honarpour ◽  
D. Peck ◽  
R. Fyfe
Keyword(s):  
Gulf Of Mexico ◽  
Gas Injection ◽  
Rock Surface ◽  
Permeability Reduction ◽  
Test Results ◽  
Asphaltene Precipitation ◽  
The Core ◽  
Asphaltene Deposition ◽  
Core Permeability ◽  
Permeability Impairment

Summary As part of studying miscible gas injection (GI) in a major field within the Green Canyon protraction area in the Gulf of Mexico (GOM), asphaltene-formation risk was identified as a key factor affecting a potential GI project. The industry has not conducted many experiments to quantify the effect of asphaltenes on reservoir and well performance under GI conditions. In this paper we discuss a novel laboratory test for evaluating the asphaltene effect on permeability. The goals of the study were to define the asphaltene-precipitation envelope using blends of reservoir fluid and injection gas, and measure permeability reduction caused by asphaltene precipitation in a core under GI. To properly analyze the effect of GI, a suite of fluid-characterization studies was conducted, including restored-oil samples, compositional analysis, constant composition expansion (CCE), and differential vaporization. Miscibility conditions were defined through slimtube-displacement tests. Gas solubility was determined through swelling tests complemented by asphaltene-onset-pressure (AOP) testing. The unique procedure was developed to estimate the effect of asphaltene deposition on core permeability. The 1-ft-long core was saturated with the live-oil and GI mixture at a pressure greater than the AOP, and then pressure was depleted to a pressure slightly greater than the bubblepoint. Several cycles of charging and depletion were conducted to mimic continuous flow of oil along the path of injected gas and thereby to observe the accumulation of asphaltene on the rock surface. The test results indicated that during this cyclic asphaltene-deposition process, the core permeability to the live mixture decreased in the first few cycles but appeared to stabilize after Cycle 5. The deposited asphaltenes were analyzed further through environmental scanning electron microscopy (ESEM), and their deposition was confirmed by mass balance before and after the tests. Finally, a relationship was established between permeability reduction and asphaltene precipitation. The results from the asphaltene-deposition experiment show that for the sample, fluids, and conditions used, permeability is impaired as asphaltene flocculates and begins to coat the grain surfaces. This impairment reaches a plateau at approximately 40% of the initial permeability. Distribution of asphaltene along the core was measured at the end by segmenting the core and conducting solvent extraction on each segment. Our recommendation is numerical modeling of these test results and using this model to forecast the magnitude of the permeability impairment in a reservoir setting during miscible GI.

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