Relative Permeability Modifiers as a Chemical Means to Control Water Production in Oil and Gas Reservoirs

2021 ◽  
Author(s):  
Ali Al-Taq ◽  
Abdullah Alrustum ◽  
Basil Alfakher ◽  
Hussain Al-Ibrahim
Keyword(s):  
Relative Permeability ◽  
Gas Flow ◽  
Water Production ◽  
Success Rates ◽  
Water Control ◽  
Overburden Pressure ◽  
The Core ◽  
Carbonate Cores ◽  
Polymer Retention ◽  
Control Water

Abstract It is challenging to control water production in horizontal wells or in vertical wells having oil and water produced from the same zone using conventional methods such as through-tubing bridge plugs or other mechanical means. Relative permeability modifiers (RPMs), known to selectively reduce the relative permeability to water with minimum impact on the relative permeability to oil or gas, are considered a promising technology for solving this problem. The current generation of RPMs, unlike the old ones, can tolerate high hardness and so have higher success rates. An extensive experimental work was carried out to evaluate three RPMs for water control in gas and oil wells. Test conditions included gas flow in sandstone cores with temperatures of up to 300°F, and oil flow in carbonate cores with temperatures as high as 220°F. The effect of initial core permeability to brine, RPM concentration, flow rate, and water-wetting surfactants on the effectiveness of RPM to reduce water production was investigated using sandstone and carbonate cores. Coreflood experiments were undertaken at downhole conditions. The end-point relative permeabilities to various phases were measured. A back pressure of 500 psi, an overburden pressure of 3,500 to 5,000 psi and flow rates of 0.1 to 5 cm3/min were used. The concentration of RPM polymers was monitored in the core effluent using total organic carbon (TOC) analyzer to determine polymer retention in the core. The results revealed that temperature adversely affected the effectiveness of all RPMs evaluated. A better reduction in permeability to water was obtained at 220°F compared to that obtained at 300°F. The use of RPM at the right concentrations was found to significantly reduce permeability to water. A better water reduction was obtained at higher polymer injection rates, which was attributed to flow-induced polymer retention. Adsorption of RPM polymer tended to alter wettability of a carbonate rock to more water-wet. This paper discusses the effects of the above parameters on the performance of RPM in sandstone and carbonate reservoirs, and it gives some recommendations for improving the success rate of these chemical applications in the field.

Simultaneous Acid Diversion and Water Control in Carbonate Reservoirs: A Case History From Saudi Arabia

2008 ◽  
Vol 11 (05) ◽  
pp. 882-891 ◽  
Author(s):  
Ali A. Al-Taq ◽  
Hisham A. Nasr-El-Din ◽  
Jimmy K. Beresky ◽  
Khalid M. Al-Naimi ◽  
Leopoldo Sierra ◽  
...  
Keyword(s):  
Saudi Arabia ◽  
Relative Permeability ◽  
Carbonate Reservoir ◽  
Water Production ◽  
Water Control ◽  
Matrix Acidizing ◽  
Associative Polymers ◽  
Acid Diversion ◽  
Associative Polymer ◽  
Control Water

Summary Matrix acidizing and water control are usually addressed as two separate issues. Associative polymers can be used to simultaneously achieve effective acidizing and water control during a single treatment. A polymer-based treatment was applied in an offshore, perforated vertical well with two sets of perforations in a carbonate reservoir in Saudi Arabia. The acid treatment was needed to restore the productivity of the upper set of perforations and reduce water production from the lower set of perforations. Experimental studies were carried out to investigate the potential use of associative polymers to control water mobility and act as an acid diverter. Coreflood experiments were conducted on reservoir cores at downhole conditions (temperature of 200°F and pressure of 3,500 psi). Extensive laboratory testing showed that associative polymers had no significant effect on the relative permeability to oil. However, the relative permeability to water was significantly reduced. This paper presents a case history where an associative polymer was applied during matrix acid treatment of a damaged well. The treatment included two stages of associative polymer solutions and 20 wt% HCl with additives. Post-stimulation treatment production data showed that oil rate increased 11.18-fold, whereas water rate decreased 1.7-fold, resulting in a reduction in the water cut from 75 to 14 vol%. The production logging tool (PLT) results indicated that the associative polymer was effective in diverting the acid into the oil producing zone. The upper set of perforations was producing most of the fluid, which further confirmed that the associative polymer significantly reduced water production from the lower zone. Introduction Matrix acidizing and water control are two important treatments conducted to enhance well performance. These treatments are commonly addressed as two separate issues. Associative polymers can be used to simultaneously achieve effective acidizing and water control utilizing a single treatment (Eoff et al. 2005). Acid diversion is an important issue contributing to the success of any matrix acid stimulation treatment. For this reason, extensive laboratory studies and field applications have been performed on several acid diverting agents as reported in the literature. Among the techniques that have been applied to improve acid coverage are: mechanical (packers, ball sealers, and particulate diverting agents) and chemicals (foam, polymers, and in-situ-gelled fluids). More recently, viscoelastic surfactants have been used extensively for diversion during matrix acid treatments, and have shown a tendency to reduce water production as reported by Nasr-El-Din et al. (2006). Relative permeability modifiers, commonly used for water control, can also be utilized for acid diversion. They can act simultaneously to enhance diversion during matrix acid treatments and impair water mobility. Eoff et al. (2005) presented laboratory and field tests, which showed that associative polymers could provide both goals in sandstone reservoirs. However, a few studies considered application of associative polymers to divert and control water production in carbonate formations. Therefore, the objectives of the present study are to:assess the effectiveness of associative polymers in reducing brine permeability in carbonate cores,design a polymer-based treatment to control water and divert acid in matrix treatments, andevaluate the use of associative polymers based on field application. This paper presents laboratory data that support the use of this new technology in carbonate reservoirs. It will also give for the first time field results on the application of associative polymers in a carbonate reservoir in Saudi Arabia. Field data were in good agreement with laboratory results.

A Novel Double-Group Crosslinked Hydrogel with High Thixotropy for Water Control in Horizontal Wells

SPE Journal ◽  
2020 ◽  
pp. 1-15
Author(s):  
Gang Li ◽  
Lifeng Chen ◽  
Meilong Fu ◽  
Lei Wang ◽  
Yadong Chen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Gelation Time ◽  
Horizontal Wells ◽  
Uniform Grid ◽  
Drilling Fluids ◽  
Water Production ◽  
Water Control ◽  
Recovery Coefficient ◽  
Metastable Structure ◽  
Control Water

Summary Horizontal wells that are completed with slotted liners often suffer from a severe water-production problem, which is detrimental to oil recovery. It is because the annulus between the slotted liners and wellbore cannot be fully filled with common hydrogels with poor thixotropy, which determines the ultimate hydrogel filling shape in the annulus. This paper presents a novel hydrogel with high thixotropy to effectively control water production in horizontal wells. This study is aimed at evaluating the thixotropic performance, gelation time, plugging performance, and degradation performance. The thixotropic performance of the new hydrogel was also investigated by measuring its rheological properties and examining its microstructures. It was found that the new hydrogel thickened rapidly after shearing. Its thixotropic recovery coefficient was 1.747, which was much higher than those of traditional hydrogels. The gelation time can be controlled in the range of 2 to 8 hours by properly adjusting the concentrations of the framework material, crosslinker, and initiator. The hydrogel could be customized for mature oil reservoirs, at which it was stable for more than 90 days. A series of laboratory physical modeling tests showed that the breakthrough pressure gradient and the plugging ratio of the hydrogel in sandpacks were higher than 9.5 MPa/m and 99%, respectively. At the same time, it was found that the hydrogel has good degradation properties; the viscosity of the hydrogel breaking solution was 4.22 mPa·s. Freeze-etching scanning-electron-microscopy examinations indicated that the hydrogel had a uniform grid structure, which can be broken easily by shear and restored quickly. This led to the remarkable thixotropic performance. The formation of a metastable structure caused by the electrostatic interaction and coordination effect was considered to be the primary reason for the high thixotropy. The successful development of the new thixotropic hydrogel not only helps to control water production from the horizontal wells, but also furthers the thixotropic theory of hydrogel. This study also provides technical guidelines for further increasing the thixotropies of drilling fluids, fracturing fluids, and other enhanced-oil-recovery polymers that are commonly used in the petroleum industry.

Successful Application of Relative-Permeability Modifiers To Control Water Production in Rose Run Fracturing

2006 ◽  
Author(s):  
Leonard Eugene Fry ◽  
Don M. Everett ◽  
Mark Allen Moody ◽  
Bradley Todd Hina ◽  
James Edward Gessel ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Water Production ◽  
Control Water

scholarly journals Stomatal Development in the Context of Epidermal Tissues

2021 ◽  
Author(s):  
Keiko U Torii
Keyword(s):  
Arabidopsis Thaliana ◽  
Molecular Genetic ◽  
Cell Lineage ◽  
Optimal Growth ◽  
Cell Types ◽  
State Transitions ◽  
Stomatal Development ◽  
Water Control ◽  
Pavement Cells ◽  
The Core

Abstract Background Stomata are adjustable pores on the surface of plant shoots for efficient gas exchange and water control. The presence of stomata is essential for plant growth and survival, and the evolution of stomata is considered as a key developmental innovation of the land plants, allowing colonization on land from aquatic environments some 450 million years ago. In the past two decades, molecular genetic studies using the model plant Arabidopsis thaliana identified key genes and signalling modules that regulate stomatal development: master-regulatory transcription factors that orchestrate cell-state transitions and peptide-receptor signal transduction pathways, which, together, enforce proper patterning of stomata within the epidermis. Studies in diverse plant species, ranging from bryophytes to angiosperm grasses, have begun to unravel the conservation and uniqueness of the core modules in stomatal development. Scope Here, I review the mechanisms of stomatal development in the context of epidermal tissue patterning. First, I introduce the core regulatory mechanisms of stomatal patterning and differentiation in the model species Arabidopsis thaliana. Subsequently, experimental evidence is presented supporting the idea that different cell types within the leaf epidermis, namely stomata, hydathodes pores, pavement cells, and trichomes, either share developmental origins or mutually influence each other’s gene regulatory circuits during development. Emphasis is taken on extrinsic and intrinsic signals regulating the balance between stomata and pavement cells, specifically by controlling the fate of Stomatal-Lineage Ground Cells (SLGCs) to remain within the stomatal-cell lineage or differentiate into pavement cells. Finally, I discuss the influence of inter-tissue-layer communication between the epidermis and underlying mesophyll/vascular tissues on stomatal differentiation. Understanding the dynamic behaviors of stomatal precursor cells and their differentiation in the broader context of tissue and organ development may help design plants tailored for optimal growth and productivity in specific agricultural applications and a changing environment.

Water Control in High-Water-Cut Oil Wells using Relative Permeability Modifiers: A Saudi Lab Study

2017 ◽  
Author(s):  
Ibrahim Al-Hulail ◽  
Muzzammil Shakeel ◽  
Ahmed Binghanim ◽  
Mohamed Zeghouani ◽  
Raed Rahal ◽  
...  
Keyword(s):  
Relative Permeability ◽  
High Water ◽  
Oil Wells ◽  
Water Control ◽  
High Water Cut ◽  
Water Cut

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.

scholarly journals Productivity Influence Factors of Tight Sandstone Gas Reservoir with Water Produced

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Yongchao Xue ◽  
Qingshuang Jin ◽  
Hua Tian
Keyword(s):  
Pressure Gradient ◽  
Relative Permeability ◽  
Gas Flow ◽  
Influence Factors ◽  
Stress Sensitivity ◽  
Consumption Pattern ◽  
Tight Sandstone ◽  
Gas Reservoir ◽  
Two Phase ◽  
Start Up

Finding ways to accelerate the effective development of tight sandstone gas reservoirs holds great strategic importance in regard to the improvement of consumption pattern of world energy. The pores and throats of the tight sandstone gas reservoir are small with abundant interstitial materials. Moreover, the mechanism of gas flow is highly complex. This paper is based on the research of a typical tight sandstone gas reservoir in Changqing Oilfield. A strong stress sensitivity in tight sandstone gas reservoir is indicated by the results, and it would be strengthened with the water production; at the same time, a rise to start-up pressure gradient would be given by the water producing process. With the increase in driving pressure gradient, the relative permeability of water also increases gradually, while that of gas decreases instead. Following these results, a model of gas-water two-phase flow has been built, keeping stress sensitivity, start-up pressure gradient, and the change of relative permeability in consideration. It is illustrated by the results of calculations that there is a reduction in the duration of plateau production period and the gas recovery factor during this period if the stress sensitivity and start-up pressure gradient are considered. In contrast to the start-up pressure gradient, stress sensitivity holds a greater influence on gas well productivity.

Core Effective and Relative Permeability Measurements for Conventional and Unconventional Reservoirs by Saturation Monitoring in High Frequency 3d Gradient NMR

2021 ◽  
Author(s):  
Brian Chin ◽  
Safdar Ali ◽  
Ashish Mathur ◽  
Colton Barnes ◽  
William Von Gonten
Keyword(s):  
Relative Permeability ◽  
Oil And Gas ◽  
Spontaneous Imbibition ◽  
Tuning Parameter ◽  
Core Flooding ◽  
Hydrocarbon Gases ◽  
Flowing Fluid ◽  
The Core ◽  
Difficult Time ◽  
Saturation Front

Abstract A big challenge in tight conventional and unconventional rock systems is the lack of representative reservoir deliverability models for movement of water, oil and gas through micro-pore and nano-pore networks. Relative permeability is a key input in modelling these rocks; but due to limitations in core analysis techniques, permeability has become a knob or tuning parameter in reservoir simulation. Current relative permeability measurements on conventional core samples rely on density contrast between oil/water or gas/water on CT (Computed Tomography) scans and recording of effluent volumes to determine relative fluid saturations during the core flooding process. However, tight rocks are characterized by low porosities (< 10 %) and ultra-low permeabilities (< 1 micro-Darcy), that make effective and relative permeability measurements very difficult, time-consuming, and prone to high errors associated with low pore volumes and flow rates. Nuclear Magnetic Resonance (NMR) measurements have been used extensively in the industry to measure fluid porosities, pore size characterization, wettability evaluation, etc. Core NMR scans can provide accurate quantification of pore fluids (oil, gas, water) even in very small quantities, using T2, T1T2 and D-T2 activation sequences. We have developed a novel process to perform experiments that measure effective and relative permeability values on both conventional and tight reservoirs at reservoir conditions while accurately monitoring fluid saturations and fluid fronts in a 12 MHz 3D gradient NMR spectrometer. The experimental process starts by acquiring Micro-CT scans of the cylindrical rock plugs to screen the samples for artifacts or microcracks that may affect permeability measurements. Once the samples are chosen, NMR T2 and T1T2 scans are performed to establish residual fluid saturations in the as-received state. If a liquid effective permeability test is required, the samples are then saturated with the given liquid through a combination of humidification, vacuum-assisted spontaneous imbibition, and saturation under pressure and temperature. After saturation, NMR scans are obtained to verify the volumes of the liquids and determine if the samples have achieved complete saturation. The sample is then loaded into a special core-flooding vessel that is invisible to the NMR spectrometer to minimize interference with the NMR signals from the fluids in the sample. The sample is brought up to reservoir stress and temperature, and the main flowing fluid is injected from one side of the sample while controlling the pressures on the other side of the sample with a back pressure regulator. The saturation front of the injected fluid is continuously monitored using 2D and 3D gradient NMR scans and the volumes of different fluids in the sample are measured using NMR T2 and T1T2 scans. The use of a 12 MHz NMR spectrometer provides very high SNR (signal-to-noise ratio); and clear distinction of water and hydrocarbon signals in the core plug during the entire process. The scanning times are also reduced by orders of magnitude, thereby allowing for more scans to properly capture the saturation front and changes in saturation. Simultaneously, the fluid flowrates and pressures are recorded in order to compute permeability values. The setup is rated to 10,000 psi confining pressures, 9000 psi of pore pressure and a working temperature of up to 100 C. Flowrates as low as 0.00001 cc/min can be recorded. These tests have been done with brine, dead and live crudes, and hydrocarbon gases. The measured relative permeability values have been used successfully in both simulation and production modelling studies in various reservoirs worldwide.

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