Baojun Bai

Preformed Particle Gel for Conformance Control: Transport Mechanism Through Porous Media

Preformed particle gel (PPG) has been successfully synthesized and applied to control excess water production in most of the mature, waterflooded oil fields in China. This paper reports on laboratory experiments carried out to investigate PPG transport mechanisms through porous media. Visual observations in etchedglass micromodels demonstrate that PPG propagation through porous media exhibits six patterns of behavior: direct pass, adsorption, deform and pass, snap-off and pass, shrink and pass, and trap. At the macroscopic scale, PPG propagation through porous media can be described by three patterns: pass, broken and pass, and plug. The dominant pattern is determined by the pressure change with time along a tested core (as measured at specific points), the particle-size ratio of injected and produced particles from the core outlet, and the residual resistance factor of each segment along the core. Measurements from micromodel and routine coreflooding experiments show that a swollen PPG particle can pass through a pore throat with a diameter that is smaller than the particle diameter owing to the elasticity and deformability of the swollen PPG particle. The largest diameter ratio of a PPG particle and a pore throat that the PPG particle can pass through depends on the swollen PPG strength. PPG particles can pass through porous media only if the driving pressure gradient is higher than the threshold pressure gradient. The threshold pressure depends on the strength of the swollen PPG and the ratio of the particle diameter and the average pore diameter.

Preformed Particle Gel for Conformance Control: Factors Affecting Its Properties and Applications

Preformed particle gel (PPG) is a particled superabsorbent crossklinking polymer that can swell up to 200 times its orginal size in brine. The use of PPG as a fluid-diverting agent to control conformance is a novel process designed to overcome some distinct drawbacks inherent in in-situ gelation systems. This paper introduces the effect of gelant compositions and reservoir environments on the two properties of PPG: swollen gel strength and swelling capacity. Results have shown that PPG properties are influenced by gelant compositions, temperature, brine salinity, and pH below 6. Temperature increases PPG swelling capacity but decreases its swollen gel strength. Salinity decreases PPG swelling capacity but increases its swollen gel strength. PPG is thermostable at an elevated temperature of 120°C if a special additive agent is added into its gelant as a composition. PPG is strengthand sizecontrolled, environmentally friendly, and not sensitive to reservoir minerals and formation water salinity. Two field applications are introduced to illustrate the criteria of well candidate selection and the design and operation process of PPG treatments. Field applications show that PPG treatment is a cost-effective method to correct permeability heterogeneity for the reservoirs with fractures or channels, both of which are widely found in mature waterflooded oil fields.

Origin and accumulation of carbon dioxide in the Huanghua depression, Bohai Bay Basin, China

The CO2 content in natural gas in the Huanghua depression, Bohai Bay Basin, China, is highly variable, ranging from 0.003 to 99.6%. Understanding the origin and distribution of the CO2 is important to assess risk prior to drilling. This study uses gas geochemistry to identify the origins of CO2 in the sedimentary basin and places these findings within a geologic context. Chemical compositions, , 3He/4He, and 40Ar/36Ar were measured for 50 gas samples collected from gas- and oil-producing wells located in different tectonic regions in the depression. From these analyses, we determined that the CO2 in the Huanghua depression originated from three sources: thermal decomposition of organic matter, thermal decomposition of carbonate minerals, and mantle degassing. Gases with low amounts (3%) of CO2 tend to be organogenic. This organogenic CO2 occurs in hydrocarbon accumulations and is characterized by values ranging from 20 to 10 and low 3He/4He (R/Ra 1, herein R and Ra represent the 3He/4He ratio of sample and air, respectively). Carbon dioxide originating from thermal carbonate decomposition occurs as a minor component (10%) in hydrocarbon gas accumulations and is characterized by a narrow range of (2 to +2) and R/Ra 1. Huanghua depression natural gases with CO2 content in excess of 15% resulted from mantle degassing and mainly occur at the intersection of faults. These gases have 3He/4He ratios in excess of atmospheric value (R/Ra 1) and ranging from 5 to 3. Volatiles from mantle degassing during the postmagmatic stage are the most likely major source for CO2 in these high-CO2-content reservoirs. Basement faults likely provide pathways for the upward migration of CO2-rich mantle fluids. Consequently, CO2-rich gas pools are locally concentrated in the Gangxi and Dazhongwang fault zones within the depression.

Case Study on Prefromed Particle Gel for In-Depth Fluid Diversion

The paper describes preformed particle gel (PPG) treatments for in-depth fluid diversion in four injection wells located in the north of Lamadian, Daqing oilfield, China. Lamadian is sandstone oilfield with thick net zones. The selected four injectors have 46 connected producers with average water cut of 95.4% before treatment. The paper reports the detailed information for the four well treatments, including well candidate selection criteria, PPG treatment optimization, real-time monitoring result during PPG injection and reservoir performance after treatment. In addition, a discussion is made to analyze why so large amount of large particles can be injected into the reservoir. Large volume of PPG suspension with concentrations of 2,000-2,500 mg/L and particle sizes of 0.06-3.0 mm was injected into each well and it took about 4 months to finish each injection. The injection volume ranges from 11,458 to 17,625 m per well with a total of 56,269 m of PPG suspension (295,680 lbs of dried PPG) for the four wells. During PPG injection, the increase of the wellhead pressure was quite stable and no PPG was produced from adjacent producers. Recorded real-time monitoring Data about injection pressure and rate, PPG particle size change during PPG injection provide invaluable information to analysis the possibility of fracture/channel in the reservoir. The treatments resulted in an oil increase of 34.8 t/d and average water cut decrease of 0.94% within 10 months after treatments. Introduction Excess water production has become a major problem for oilfeld operators as more and more reservoirs mature due to long term of water flooding. Higher levels of water production result in increased levels of corrosion and scale, increased load on fluid-handling facilities, increased environmental concerns, and eventually well shut-in. Consequently, producing zones are often abandoned in an attempt to avoid water contact, even when the intervals still maitain large volumes of remaining hydrocarbons. Controlling water production has become more and more important to the oil industry. Reservoir heterogeneity is the single most important reason for low oil recovery and early excess water production. Most oilfields in China, which were discovered in continental sedimentary basins, are characterized by complex geological conditions and high permeability contrast inside reservoirs. To maintain reservoir pressure, these reservoirs were developed by water flooding from early stage of their development. Many of them have been hydraulically fractured, intentionally or unintentionally, or have been channeled due to mineral dissolution and production during waterflooding (Liu, 2006). Reservoirs with induced fractures or high-permeability channels are quite common in the mature oilfields. Gel treatment is a cost-effective method to improve sweep efficiency in reservoirs and to reduce excess water production during oil and gas production. Traditionally, gels are usually placed near wellbore of production or injection wells to correct inter-layer heterogeneity or heal fracture. However, the remaining oil on the top of a thick heterogeneous layer has become the most important target to improve oil recovery as a reservoir matures. In-depth diversion gels (Seright, 2004, Frampton, 2004, Sydansk, 2004, 2005, Cheung, 2007, Rousseau, 2005, Bai, 2007) have been reported to penetrate deeply into higher permeability zones or fractures and seal or partially seal them off thus creating high flow resistance in former, watered-out, high permeability portion of the zones. When successful, these gel systems divert a portion of the injection water into areas not previously swept by water shown in Fig. 1. Traditionally in-situ gels have been widely used to control conformance. The mixture of polymer and crosslinker called gelant is injected into target formation and react to form gel to fully or partially seal the formation at reservoir temperature (Sydansk, 1992, Jain, 2005). So the gelation occurs in reservoir conditions. A new trend in gel treatments is applying preformed gels for the purpose because the preformed gels are formed at surface facilities before injection and no gelation occurs in reservoirs so they can overcome some distinct drawbacks inherent in in-situ gelation systems, such as lack of

Submicron-Pore Characterization of Shale Gas Plays

Gas storage and flow behavior in the shale gas rocks are complex and hard to identify by conventional core analysis. This study integrates clustering analysis techniques from material science, petrophysics, and petrology to characterize North American shale gas samples from Utica, Haynesville, and Fayetteville shale gas plays. High pressure (up to 60,000 psi) mercury porosimetry analysis (MICP) determined the pore size distributions. A robust, detailed tomography procedure using a dual-beam (Scanning Electron Microscope and Focused Ion Beam, also called SEM-FIB) instrument successfully characterized the submicron-pore structures. SEM images revealed various types of porosities. Pores on a scale of nanometers were found in organic matter; they occupy 40−50% of the kerogen body. Two-hundred two-dimensional SEM images were collected and stacked to reconstruct the original pore structure in a three-dimensional model. The model provided insights into the petrophysical properties of shale gas, including pore size distribution, porosity, tortuosity, and anisotropy. This paper presents the pore model constructed from Fayetteville shale sample. The work used X-ray diffraction (XRD) to semi-quantify shale gas clay and non-clay minerals. The Haynesville and Utica (Indian Castle formation) shale samples have a high illite content. The Utica (Dolgeville formation) shale samples show high calcium carbonate (calcite) content. Moreover, wettability tests were performed on the shale samples, and the effect of various fracturing fluid additives on their wettability was tested. Most additives made the shale gas surfaces hydrophilic-like (water-wet). Introduction Unconventional natural gas resources have grown in importance as a complement to conventional fossil fuels as world energy demand has increased. Shale gas is the second largest unconventional energy resource after heavy oil. Recently, the United States Geological Survey (USGS) estimated that tight sands and gas shale in the United States may hold up to 460 Tcf of gas. There are about 200,000 unconventional gas wells in low-permeability sands, coal-bed methane deposits, and shale gas in the lower 48 states. Shale gas is more environmentally friendly and attractive compared to other energy resources due to its ecological advantages (low levels of carbon dioxide CO2 emission) and safety qualities (insignificant sulfur dioxide contents, H2S%). Many petrophysical properties of the unconventional tight gas formations are significantly different from those of conventional reservoirs. In particular, such formations have nano-scale pores and channels, a unique pore structure, and the unusual wettability, transport, and storage properties. These differences produce the fluid flow mechanisms different from those in conventional gas plays, especially when the size of the pore throats differs from the size of the saturating fluid molecules by only slightly more than one order of magnitude. Despite the practical importance of this topic, very little is known about it. Commercial production from extremely low permeability gas reservoirs requires hydraulic fracturing stimulation at the beginning of well production. Proper selection of a fracturing fluid is key to successful stimulation. Currently, selection of hydraulic fracturing fluids for unconventional gas wells borrows from conventional oil and gas techniques. However, shale gas plays have unique properties. For example, the size of the pore throats in shale may differ from the size of the saturating fluid molecules by only slightly more than one order of magnitude. The physics of the fluid flow in these rocks, with permeabilities in the nanodarcy range, is poorly understood.

A Comprehensive Review of Polyacrylamide Polymer Gels for Conformance Control

Abstract Polymer gels have been designed and successfully applied to improve sweep efficiency and to reduce excessive water production by minimizing reservoir heterogeneity. Based on their compositions and application conditions, polyacrylamide polymer gels can be classified into three types: in-situ monomer-based gel, in-situ polymer-based gels, and preformed particle gels. Initially, in-situ monomer gels which are mainly composed of acrylamide were developed for water shutoff. Conventional in-situ polymer gels include metal-cross linked polyacrylamide gels and organic-cross linked polyacrylamide gels. Preformed gels include preformed particle gels, pH sensitive microgels, and micro- and nano-gels. A few directions are suggested for future research on novel gels, such as gels used for in-depth fluid diversion and gels for severe reservoir environments.

Modeling Particle Gel Propagation in Porous Media

Gel treatments are a proven cost-effective method to reduce excess water production and improve sweep efficiency in waterflood reservoirs. A newer trend in gel treatments uses particle gel (PG) to overcome some distinct drawbacks inherent in in-situ gelation systems. In this paper, we present a conceptual numerical model, based on laboratory tests and analyses, to simulate PG propagation through porous rock. In particular, we use a continuum modeling approach to simulate PG movement and its impact on isothermal oil and water flow and displacement processes. In this conceptual model, the PG is treated as one additional “component” to the water phase. This simplified treatment is based on the following physical considerations: (1) PG is mobilized only within the aqueous phase by advection in reservoirs; (2) PG, once retained in the porous media, will occupy pore space in pore bodies or pore throats and therefore reduce the permeability to bypassing water or oil; and (3) PG mobilization may not occur through pores or pore throats until some thresholds in pressure and/or pressure gradients are achieved and these threshold conditions are described by analogy to non-Newtonian fluid or non-Darcy flow in porous media, i.e., by a modified Darcy’s law. The model is able to predict and evaluate the effects of PG as a conformance control agent to improve oil production and control excess water production. Introduction Excess water production has become a major problem for oilfeld operators to deal with, as more and more reservoirs, subject to long-term water flooding, become mature. In addition to rapid reduction in oil recovery, high rates of water production also create many problems from corrosion and fluid-handling facility to waste water handling and eventually lead to well shut-in. Consequently, many producing zones are often abandoned in an attempt to avoid water contact, even when the formations still contain large volumes of remaining hydrocarbons. Controlling water production has become more and more important to both the oil industry and environmental protection. Gel treatments, if used properly, are very effective to improve reservoir conformance and to reduce excess water production during oil and gas production. Traditionally in-situ gels have been widely used for these purposes. The mixture of polymer and crosslinker, called gelant, is injected into target formation and reacts to form gel to fully or partially seal the formation at reservoir temperature (Sydansk, 1992; Jain, 2005). Thus the gelation occurs in reservoir conditions. A new trend in gel treatments is applying preformed gels, because the preformed gels are formed at surface facilities before injection, no gelation occurs in reservoirs, so they can overcome some distinct drawbacks inherent in in-situ gelation systems, such as lack of gelation time control, uncertainness of gelling due to shear degradation, chromatographic fractionation or change of gelant compositions, and dilution by formation water. The preformed gels include preformed bulk gels (Seright, 2004), partially preformed gels (Sydansk, 2004 and 2005), and particle gels which include mm-sized preformed particle gel (PPG) (Li, 1999; Coste 2000; Bai, 2004 and 2007), microgels (Chauveteau, 2001 and 2003; Rousseau 2005; Zaitoun 2007) and pH sensitive crosslinked polymer (Al-Anazi, 2002; Huh, 2005), mm-sized swelling polymer grains which is a similar product with PPG (Pyziak et al., 2007; Larkin and Creel, 2008; Abbasy et al., 2008), and Bright Water® (Pritchett, 2003; Frampton, 2004). Their major differences are in their sizes and swelling times. Published documents indicate that several particle gels were economically applied to reduce water production in mature oilfields. Microgel was applied to one gas storage well to reduce water production (Zaitoun, 2007). Bright water was used for more than 10 wells treatments with BP and Chevron (Cheung, 2007). PPGs were applied in about 2,000 wells to reduce fluid channels in waterfloods and polymer floods in China (Liu, 2006; Bai, 2008). Recently, Occidental Oil Company (Pyziak et al., 2007) and Kinder-Morgan (Larkin and Creel, 2008) used the mm-sized swelling polymer grains to control CO2 breakthrough for their CO2 flooding areas and promising results have been found. To understand particle gel transport through porous media, Bai et al. (2007) reported their experimental results of PPG

Efficient Simulation for Low Salinity Waterflooding in Porous and Fractured Reservoirs

Low-salinity brine injection has emerged as a promising, cost-effective improved oil recovery (IOR) method for waterflooding reservoirs. Laboratory tests and field applications show that low-salinity waterflooding could lead to significant reduction of residual oil saturation. There has been a growing interest with an increasing number of low-salinity waterflooding studies. However, there are few quantitative studies on flow and transport behavior of low-salinity IOR processes. This paper presents a general mathematic model (1) to incorporate known IOR mechanisms and (2) to quantify low-salinity waterflooding processes. In our mathematical conceptual model, salt is treated as an additional “component” to the aqueous phase, based on the following physical considerations: salt is transported only within the aqueous phase by advection and diffusion, and also subject to adsorption onto rock solids; relative permeability, capillary pressure, and residual oil saturation depend on salinity. Interaction of salt between mobile and immobile water zones is handled rigorously using a multi-domain approach. Fractured rock is handled using the multiple-continuum model or a discrete-fracture modeling approach. The conceptual model is implemented into a general-purpose reservoir simulator for modeling low-salinity IOR processes, using unstructured, regular, and irregular grids, applicable to 1-D, 2-D, and 3-D simulation of low-salinity water injection into porous media and fractured reservoirs. As demonstrated, the model provides a general capability for quantitative evaluation of low-salinity waterflooding in site-specific investigations. Introduction Waterflooding has been widely used as a secondary method to improve oil recovery for most oil reservoirs. Apart from formation damage, water floods are traditionally designed without considering the composition of the injected brine. However recent laboratory coreflood studies and field tests have showed that low-salinity waterflooding could result in a substantial oil recovery increase (2-40%) over traditional water flooding in many cases, depending on the reservoir formation minerals and brine composition (McGuire, et al, 2005, Lager, et al, 2008). The possible mechanisms for low-salinity waterflooding to improve oil recovery could be attributed to: (1) the wettability change towards water wet as a result of clay migration (Tang and Morrow, 1999); (2) the pH increase as a result of CaCO3 dissolution, which increase oil recovery by several mechanisms including wettability alteration, generation of surfactants, and reduction in IFT (McGuire, et al, 2005,); and (3) multiple-component ion exchange (MIE) between clay mineral surfaces and the injected brine (Larger et al, 2006). In general, the oil recovery improvement during low-salinity water flooding is recognized to depend on MIE, clay content, formation water composition (Ca, Mg), and oil composition. In the petroleum industry, there has been a growing interest with an increasing number in low-salinity waterflooding studies. However, most of the work has focused on the extent of low-salinity water effect on improved oil recovery and the mechanisms of wettability alteration. In comparison, there are few quantitative studies on flow and transport behavior of lowsalinity IOR processes. Jerauld et al (2006) modeled low-salinity waterflooding as a secondary and tertiary recovery processes in one dimensional model using salinity dependent oil/water relative permeability functions, resulting from wettability. Tripathi et al (2008) studied the flow instability associated with wettability alteration using a Buckley-Leveret type, analytical model in one dimension. In this paper, we present a general numerical model for low-salinity water flooding in multidimensional, porous or fractured reservoirs. The model formulation incorporates known IOR mechanisms by low-salinity flooding for simulating low-salinity waterflooding processes. Two models, one homogenous model and one fracture model, were run to demonstrate the use of the proposed modeling approach in simulation of low-salinity water flooding.

Optic Imaging of Single and Two-phase Pressure-Driven Flows in Nano-scale Channels

Microfluidic and nanofluidic devices have undergone rapid development in recent years. Functions integrated onto such devices provide lab-on-a-chip solutions for many biomedical, chemical, and engineering applications. In this paper, a lab-on-a-chip technique for direct visualization of the single- and two-phase pressure-driven flows in nano-scale channels was developed. The nanofluidic chip was designed and fabricated; concentration dependent fluorescence signal correlation was developed for the determination of flow rate. Experiments of single and two-phase flow in nano-scale channels with 100 nm depth were conducted. The linearity correlation between flow rate and pressure drop in nanochannels was obtained and fit closely into Poiseuilles Law. Meanwhile, three different flow patterns, single, annular, and stratified, were observed from the two-phase flow in the nanochannel experiments and their special features were described. A two-phase flow regime map for nanochannels is presented. Results are of critical importance to both fundamental study and many applications.

Preformed-Particle-Gel Extrusion Through Open Conduits During Conformance-Control Treatments

Millimeter-sized (10 um~mm) preformed particle gels (PPGs) have been used successfully as conformance control agents in more than 5,000 wells. They help to control both water and CO2 production through high-permeability streaks or conduits (large pore openings), which naturally exist or are aggravated either by mineral solutions or by a high injection pressure during the flooding process. This paper explores several factors that can have an important impact on the injectivity and plugging efficiency of PPGs in these conduits. Extensive experiments were conducted to examine the effect of the conduit’s opening size and the PPG strength on the ratio of the particle size to the opening diameter, injectivity index, resistance factor, and plugging efficiency. Five-foot tubes with four internal diameters were designed to emulate the opening conduits. Three pressure taps were mounted along the tubes to monitor PPG transport and plugging performance. The results show that weak gel has less injection pressure at a large particle opening ratio compared to strong gel. PPG strength impacted injectivity more significantly than did particle opening ratio. Resistance factor increased as the brine concentration and conduit opening size increased. PPGs can significantly reduce the permeability of an open conduit and their plugging efficiency depends highly on the particle strength and the conduit’s opening size. The particle size of PPG was reduced during their transport through conduits. Experimental results confirm that the size reduction was caused by both dehydration and breakdown. Based on the lab data, two mathematical models were developed to quantitatively calculate the resistance factor and the stable injection pressure as a function of the particle strength, particle opening ratio, and shear rate. This research provides significant insight into designing better millimeter-sized particle gel treatments intended for use in large openings, including open fractures, caves, worm holes, and conduits. Introduction Excess water production in oil fields is becoming a challenging economical and environmental problem as more reservoirs are maturing. An estimated average of three barrels of water are produced for each barrel of oil produced worldwide (Bailey et al., 2000). It is estimated that the total cost to separate, treat, and dispose of this water is approximately