Abstract One of the main problems in the decline of the production of any field is associated with the presence of fractional flow of water and its detrimental effect on the wells. This situation has led to a whole field of study regarding the understanding of this phenomenon, aimed at mitigating this through the application of several technologies and best reservoir management practices. This paper will present the analysis, development and results obtained from the application of a relative permeability modifier (RPM) in a naturally fractured carbonate reservoir under high pressure and temperature conditions (HP / HT). This is in addition to a series of so-called "high potential" interventions, whose production benefits result in a profitable business case applying an optimized shut-in time strategy in high production wells. Finally, a summary with various results of the application of the RPM in different wells will allow broadening the criteria of its application. Although there are cases of success, there will be others in which a better diagnosis must be made to ascertain its effectiveness in the short or medium term, which may be related to the identification of the preferential means of flow in a naturally fractured reservoir, which by its nature, results in a technical-technological challenge, both in its identification and discretization as well as in the field applications.

In fracturing treatments performed in unconventional reservoirs, propping agents are normally placed in the generated fractures using low viscosity fracturing fluids and friction reducers. It is generally accepted that a majority of the propping agents settle closer to the wellbore due to the poor transport characteristics of these thin fluids, limiting the propped area to the near wellbore region. This preferential settling can leave a majority of the generated fracture unpropped, and can result in: Reduced effective fracture-reservoir contact Low productivity and recovery of the stimulated well or reservoir Generation of long un-propped fractures Inefficient usage of the carrying fluids and chemicals Extensive lab testing was performed to demonstrate the impact of variable viscosity on proppant transport and deposition. Fluids were built that covered a range of realistic slickwater viscosities and were then run through a slot with various proppant types and loadings, to observe the changes in deposition. This included the novel process of changing the viscosity within the same test run to simulate changes during an individual treatment. The new process resulted in a substantially improved placement and distribution of typical conventional propping agents, including natural sand and ceramic proppant, and the effective placement of the proppants further away from the wellbore creating a longer propped and more conductive fracture. While designed for unconventional reservoir stimulations, the novel process can also be utilized in fracture stimulations of tight or conventional reservoirs, and results in: Assured connectivity between the fracture and wellbore Maximized propped fracture length and height Maximized reservoir contact Engineered placement of the proppant in fracture or complexity as required Reduced use of water to create a similar or longer propped fracture length Considering the improved proppant distribution in many simulated cases, this paper will review the development of the new process, present the results, and show the benefits to the user. The new proposed process to improve proppant distribution will assure better productivity and higher hydrocarbon recovery factors in hydraulically fractured unconventional reservoirs. It will be beneficial for completions and reservoir engineers who wish to improve the drainage area and ultimate recovery in their assets.

Abstract Many application and operational methods have been developed for applying carbonate matrix acidizing to successfully stimulate heterogeneous and long horizontal openhole zones. These methods have also been implemented during acid fracturing to various degrees of success. This paper discusses in detail the laboratory assessment of a biodegradable material for acid diversion in highly fractured formations. Diversion in fracture acidizing is extremely challenging because of the high pumping rate, extreme pressures, and larger volumes of acid compared to matrix acidizing. To effectively stimulate natural or pre-existing fractured formations, the diverting agent should be able to bridge not only at the perforations, but inside the fracture system, too. Historically, several methods have been implemented for acid-fracturing diversion, such as ball sealers, viscous fluids, packers, etc., resulting in limited success in formations with natural or pre-existing fractures. This paper discusses the use of an acid diverter that consists of biodegradable particles with different sizes and hardness. The particle size ratios are specifically designed where large particles will bridge in the fractures while the smaller particles "nest" in the pore throat of the bridged larger particles. This leads to quick, efficient blockage of fractures and acid diversion. The laboratory assessment of this biodegradable material was conducted at various temperatures up to 300°F and consists of (1) degradation in 3% KCl, live 15 wt% HCl, and spent 15% HCl, and (2) fluid loss using slotted disks at different diverter concentrations. The fractures were mimicked in the laboratory using a stainless steel slotted disk in a high-pressure/high-temperature (HP/HT) cell. The dissolution rate of the particles was observed to be a function of time and temperature. The dissolution rate of the diverter was higher in water as compared to 15 wt% HCl acid. The stability of the biodegradable diverter was conducted at 300°F. The filter cake was stable up to 30 minutes when 1.0 ppt of the biodegradable diverter was used. The results of this study indicate that the biodegradable diversion material can be used as an effective alternative diversion method to seal natural or pre-existing fractures.

Abstract Hydrophobically modified hydrophilic polymers (HMHPs) have numerous applications in the petroleum industry, among which stand out relative permeability modifiers (RPMs) for acid diversion, drilling, fracturing, water control, water-injection profile modification, or improved oil recovery (IOR) operations. The efficacy of the polymeric RPM is attributed to a bimodal mechanism of action, which involves the association of the hydrophobic appendages in addition to adsorption of the amphoteric material to the formation surface. As a result, one challenge associated with the use of HMHPs is the pressure increase often observed when the material enters the formation. A second limitation is the inability to reverse the effect of the treatment fluid, which can be significant when the HMHP is overdisplaced, resulting in a reduction of flowback fluid, or when operational requirements call for placement of a deactivated HMHP that can be selectively activated at a desired time and location. Because of the self-diverting nature of the HMHP discussed in this paper, field deployment has been limited to near-wellbore (NWB) applications. Within this context, a linear surfactant additive [sodium dodecyl sulfate (SDS)] has been an effective mitigation strategy against such self-diverting characteristic; however, this also inhibits other desirable HMHP properties. Restoration of the native RPM properties was achieved using a surfactant control agent that allows on-demand RPM reactivation. Recently, it was realized that the sodium dodecyl sulfate has a much higher affinity for hydroxypropyl-β-cyclodextrin (HPCD) than HMHP. This paper discusses developments that allow for improved injectivity of HMHPs when used as RPMs for water-control operations. In addition, this study attempts to advance the existing understanding of the performance and associative mechanism of action of RPMs. Currently, there is a lack of consensus about the role hydrophobic modifications play in HMHP performance. Using host-guest attraction, the nature of the hydrophobic moieties is revealed, which compliments the current body of literature related to the use of HMHP in the petroleum industry. To this end, adsorption, fluid loss, and coreflow results prove the increased affinity of the surfactant for HPCD serve to release HMHP from the HMHP/linear-surfactant complex, reactivating the HMHP to its original associative mechanism-based RPM-performance profile.

Abstract Excessive undesired fluid production, either water or gas, is a widespread problem withinthe oil and gas industry that can detrimentally affect the profitability of hydrocarbon-producing reservoirs, thus limiting their economic life. A wide variety of chemical technologies have been implemented throughoutthe years for controlling unwanted fluid production with some degree of success. However, when these types of treatments are applied to horizontal or highly deviated wells, placement control becomes a critical factor. Depending on fluid density differences and wellbore deviation, conventional conformance treatments can slump/rise along horizontal sections, compromising the placement accuracy and overall treatment success. This paper discusses the development and application of a thixotropic conformance sealant (TCS) system specifically designed to help control unwanted fluid production in horizontal or highly deviated wellbores. The stress-dependent (thixotropic) rheological properties of the TCS system provides rapid viscosity increase afterplacement, allowing the treatment to remain in place until in-situ crosslinking occurs at a predicted time, helping provide a competent and precise seal across the targeted area. The TCS system is based on an organic-crosslinked polymer gel system combined with optimized rheological modifiers. It provides a predictable and controllable crosslinking time to obtain adequate placement. It can be placed into the wellbore by bullheading or using a coiled tubing (CT) unit. Once it is strategically placed into the zone to be shut off, in-situ gelation is activated by the reservoir temperature, plugging the permeability of the treated area, thereby limiting undesired fluid flow. The TCS system can be formulated to allow penetration into the formation matrix or to bridge off at the formation face for limited leakoff, to help provide a controlled and shallow penetration at the formation face. Laboratory data ispresentedas well as preliminary results of field applications. Other thanthixotropic cement slurries, the TCS system is the first conformance technology tailored to horizontal applications within the oil and gas industry, helping reduce excessive undesired fluid production while extending the economic life of the wellbore and reservoir. The TCS system is applicable to different completion types such as openhole, slotted liners, openhole gravel-packs (OHGPs), and casedhole gravel-packs (CHGPs), among others.

Abstract This work discusses application of an advanced placement model for optimizing stimulation treatments in high water-cut wells. Stimulation treatments in high water-cut wells are challenging because they can lead to an undesired increase in water production. Associative polymers have been successfully used as diverters for addressing this challenge, and effective treatments have been performed based on experience and guidelines. However, further optimization of such treatments can be achieved using fluid placement models. Model-based treatment design has been described previously but has not been comprehensively applied for diversion by associative polymers. In this work, a transport model was developed for relative water permeability reduction by associative polymers and diversion of stimulation fluids in the pay zone. The model accounted for the mass transport and adsorption of the polymer in the formation. The transport model was integrated into a near-wellbore (NWB) fluid placement model to simulate fluid distribution in a heterogeneous layered reservoir and the effect on total skin, production/injection profiles, and surface/bottomhole pressures (BHPs) during the treatment. The paper describes case studies based on actual field treatments to demonstrate the application of the integrated model for optimizing stimulation treatments. Acid-to-diverter stage volumes, number of diverter stages, polymer concentration, and injection rates are identified as important design parameters. Based on model results, it is observed that polymer placement results in increased total skin in water-bearing zones, leading to lower post-treatment water production. Further, the optimum number and volume of diverter stages for effective diversion vary with injection rate and are governed by the non-equilibrium polymer adsorption behavior and the self-diversion effect during placement. It is concluded a single treatment design might not be suitable across multiple wells, and well-specific optimization of the pumping schedule is necessary. Because multiple parameters affect the treatment, simultaneously leading to results that are not intuitive, the placement model should be used for the treatment design. This paper discusses application of an advanced fluid placement model, which provides insight into the diversion by associative polymers during stimulation treatments. The model is useful for optimizing stimulation treatments in wells with high water cut and reducing costs associated with undesired water production.

Abstract Conformance gels based on nanosilicas are used as environmentally acceptable materials for plugging and sealing water- or gas-producing zones and controlling water production. Because of the lower pH(compared to sodium silicate solutions) of these solutions, they are environmentally acceptable in the North Sea area. The gelling agents required to activate the materials to produce gels are typically common salts, such as sodium chloride and potassium chloride. The reduced environmental impact of nanosilica has led to its commercial success in the North Sea. At temperatures greater than 80°F, the gel time of nanosilica can be controlled to desirable values by adjusting concentrations of the gelation agents. The nanosilicas that are currently used in the oilfield, however, are not suitable for low-temperature applications (e.g., below 80°F) because of extremely long gel times. This paper describes a new nanosilica system that demonstrates non-spherical-shaped nanosilica particle assemblies, such as rod-like and string-of-pearl geometries that display superior gelation activity in the presence of salts, exemplified by sodium chloride, compared with their spherical counterparts. These materials can gel in a reasonable time frame in the presence of an activator at temperatures as low as 50°F. A trend of increasing reactivity in nanosilicas based on their geometries is presented in this paper. In particular, nanosilicas with a high aspect ratio render stable gels in a shorter period of time than their spherical counterparts. It is proposed that the aspect ratio could enable formation of a networked superstructure of silica at lower concentrations than required for a networked structure of nanosilica spheres of similar diameter.

Abstract Hydrocarbon production and recovery maximization can be a challenging task in some specific areas or reservoirs. Specifically, in low permeability environments, hydraulic fracturing is a necessary step to improve the wells productivity and it can be easily justified or applied in reservoirs where a nearby water bearing zone is not present or the water bearing zone is far away from the productive horizons. When bottom water or water bearing zones are located near the oil producer layers, hydraulic fracture stimulation is normally aborted or the potential layer is abandoned or not completed; unfortunately, the luxury of stimulation or completion abortion is not really the best decision because a large amount of hydrocarbons is located in such complex environments. For the situations where the fracture stimulation could not be avoided, the industry has used different alternatives to minimize water production. These include selective perforation and controlled fracture stimulation, selective water control treatment into the water producer layer followed by fracturing, or combining the water control and fracture stimulation in one. For the latter methodology, the water control chemical is squeezed first into the fractured interval or the chemical is added into the fracturing fluid pad to minimize water mobility. However, this methodology relies on the compatibility of the fracturing fluid and the water control chemicals or the migration of the water control chemical from the fracturing fluid system to the water source layers to be effective. This paper proposes a new methodology to minimize water intrusion in cases where fracture stimulation is necessary in areas with bottom water or water bearing zones near the oil producer layers by performing on-the-fly coating of proppant with a relative permeability modifier (RPM) chemical. In the new proposed methodology, water mobility in the water producer layer will be controlled by the proppant bed coated by the RPM.

Abstract Horizontal wellbores can present unique problems during water and gas shutoff operations. The primary challenges include the extended length of many horizontal wells, which could be outside the reach of coiled tubing (CT), and the fact that many are completed with open holes, gravel packs, or slotted liners. With gravel pack and slotted liner completions, it can be extremely difficult, if not impossible, to obtain complete zonal isolation. Even when the offending water or gas producing zones are clearly demarcated from the producing zones, chemical remediation remains arduous. Mechanical plugs can be set inside gravel pack screens or slotted liners and a chemical sealant can be pumped into this isolated internal section. However, it is difficult to limit fluid flow in the outer annular space. Because most chemical sealants are designed to have relatively low viscosity, they tend to slump to the low side of the wellbore, either inside or outside of this isolated section. Consequently, the water and/or gas zones are not uniformly exposed to the treatment, which could result in an incomplete seal. Because more horizontal wells are being drilled, water/gas shutoff systems are necessary for these types of completions. An ideal sealant system would exhibit flow properties facilitating pumping and placement while, immediately upon placement in the desired location, resist slumping by behaving as a thick paste. This paper presents three systems designed to address the challenges associated with treatment of zones within horizontal wellbores. The objective was to develop sealant systems that would not slump upon placement and subsequently undergo polymerization, crosslinking, or setting and provide lasting seals to prevent water/gas flow. The fluids discussed include polymeric and monomeric gels and a Sorel cement based system, which additionally contains additives to provide slump resistant properties. The chemistries that impart the slump resistant properties are discussed. In addition, laboratory data is presented to include slump measurements, gelation times, and flow resistance measurements.

Abstract Excessive undesired fluid production of water or gas can limit the economic life and profitability of hydrocarbon reservoirs. A variety of techniques for controlling water production have been attempted within the oil industry, including mechanical and chemical treatments. Chemical treatments can become more challenging when applied in reservoirs with either natural or induced fractures. More specifically, placement control becomes a critical factor, particularly within highly fractured and depleted reservoirs. This paper presents the development and optimization to further improve a widely used organically crosslinked polymer gel system by adding foaming properties to the innovative fluid system. Referred to as a foamed conformance polymer (FCP) in this work, the system can improve placement in naturally fractured carbonate formations for water and gas control applications. The standard (nonfoamed) organically crosslinked polymer system is based on a copolymer of acrylamide and t-butyl acrylate (PAtBA) crosslinked with polyethyleneimine (PEI). This FCP system can be foamed up to 70% v/v quality to be applied within a wide temperature range (40 to 350°F) with little to no effect on gelation time, providing a stable foam that maintains sealing properties. This paper discusses the following parameters: (1) FCP advantages and considerations, (2) FCP system components to develop foam properties, (3) FCP performance testing to optimize foaming properties up to 70% v/v quality at elevated temperature, and (4) sealing capabilities of the FCP system. Addition of foaming properties to this conformance polymer gel system adds the following benefits: (1) improved placement in depleted, naturally fractured or fissured carbonate reservoirs, (2) reduced hydrostatic pressure (density can be lowered to ~2.4 lbm/gal), allowing better control of surface pressure while placing the treatment into the targeted zone, (3) improved ability to fill fractures and displace reservoir fluids by providing a system with fluid-loss control properties, and/or (4) diverting fluid properties for optimum coverage when targeting long intervals. The FCP produces a high-quality, stable foamed solution to help effectively seal natural fissures and fractures for reduced flow of unwanted water and/or gas.

The existence of high-permeability features, such as fissures, fractures, and eroded-out zones, diminishes the sweep efficiency of any water, gas, or polymer flooding operation. Placing crosslinked conformance polymer gels or other types of blocking agents in injection and/or production wells can generate the necessary flow diversion for increasing the recovery factor of enhanced oil recovery/improved oil recovery (EOR/IOR) treatments. This paper evaluates a high-molecular-weight (HMW) organically crosslinked polymer (OCP) (referred to as HMW-OCP) gel system for such scenarios. This conformance technology is the result of crosslinking reactions between HMW polyacrylamide and polyethylenimine (PEI). The relatively medium viscosities of the fluids caused by the HMW of the components of the system allows for in-depth gel placement in fractures and high-perm channels, without invading the matrix of the rock. A low-molecular version of this polymer system has proven to successfully control water production in matrix applications. This HMW-OCP system gelation occurs gradually with time and temperature and can be designed to suit the need for short and long placement times. Optimization of gelation times using chemical activators and bimodal distribution of polymer molecular weights (MWs) is discussed. Fast hydration of the base polymer provides on-the-fly mixing capabilities. Also, the use of all liquid polymers and additives allows ease of transportation, handling, and storage and mixing of large volumes of material usually necessary for this type of treatment. Laboratory test results show long-term plugging capabilities, thermal stability, and fluid-loss control.

Abstract Relative permeability modifiers (RPMs) have been used by the oil and gas industry for more than two decades to selectively help reduce excessive formation water production. RPM systems are appealing to operators because their deployment simplicity requires no zonal isolation (i.e., bullhead-type treatments). This paper discusses the application of a novel RPM system that was originally developed for water control; however, its application was extended to hydraulic fracturing, acid stimulation, overbalanced workover interventions, and waterflooding. This RPM system is based on a hydrophobically modified water-soluble polymer that, once adsorbed to the surface of the rock, selectively reduces the effective permeability to any aqueous fluid with little or no damage to oil or gas production in both injection and production modes. The hydrophobic modification to the base polymer chain adds unique associative properties to the system that allow multiple novel applications. The following applications are discussed in this paper: (1) the combination of the RPMs with hydraulic fracturing stimulation treatments in intervals previously bypassed because of their proximity to mobile water zones; (2) the combination of RPMs with acid (matrix and non-matrix) stimulation treatments used as a diverting and water control agent; (3) RPMs during overbalanced workover interventions (i.e., wellbore cleanouts, tubing-conveyed perforating (TCP), and gravel packing) used as a fluid-loss control agent; and (4) RPMs during waterflooding for improved profile modification as a diverting agent. Because this RPM does not affect hydrocarbon permeability, this system does not require the use of breakers or a cleanup stage, eliminating possible negative impacts on post-stimulation well productivity. To date, more than 3,000 treatments have been performed with this RPM system. This paper discusses the RPM performance testing and a wide variety of case histories detailing the applications described in different types of reservoirs and wellbore completions.