Kazakhstan owns one of the largest global oil reserves (~3%). This paper aims at investigating the challenges and potentials for production from weakly-consolidated and unconsolidated oil sandstone reserves in Kazakhstan. We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves, in Kazakhstan, were studied in terms of the depth, pay-zone thickness, viscosity, particle size distribution, clay content, porosity, permeability, gas cap, bottom water, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, geological condition, including the existing structures, layers and formations were addressed for different reserves. Weakly consolidated heavy oil reserves in shallow depths (less than 500 m) with oil viscosity around 500 cP and thin pay zones (less than 10 m) have been successfully produced using cold methods, however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical in comparison to the similar cases in North America. The complicated tectonic history, necessitates the geomechanical models to strategize the sand control especially in cased and perforated completion. These models are usually avoided in North America due to the less problematic conditions. Further investigation has shown that Inflow Control Devices (ICDs) could be utilized to limit the water breakthrough, as water coning is a common problem, which initiates and intensifies the sanding. This paper provides a review on challenges and potentials for sand control and sand management in heavy oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.

Standalone screens (SAS) have been widely employed as the main sand control solution in thermal projects in Western Canada. Most of the test protocols developed to evaluate screen designs were based on the scaled screen coupons. There have been discussions regarding the reliability of such tests on scaled coupons. This paper presents the results of the tests on full-scale wire-wrapped screen (WWS) and slotted liner coupons for typical McMurray Formation sands. A large-scale sand control evaluation apparatus has been designed and built to accommodate all common SAS with 3 1/2″ in diameter and 12″ in height. The set-up provides the capability to have the radial measurement of the pressure across the sand pack and liner, for three-phase flow. We outline certain challenges in conducting full-scale testing such as establishing uniform radial flow and measuring the differential pressure. Produced sand is also measured during the test. The main outputs of the test are to assess the sand control performance and the mode of sanding in different flow direction, flow rates and flow regimes. We were able to establish uniform radial flow in both high and low permeability sand packs. However, the establishment of the radial flow in sand packs with very high permeability was extremely challenging. The pressure measurement in different points in radial direction around the liner indicated a uniform radial flow. Results of the tests on a representative PSD from McMurray Formation on the WWS and slotted liner coupons with commonly used specs in the industry have shown similar sanding and flow performances. We also included aperture sizes smaller and larger than the common practice. Similar to the previous large-scale tests, narrower apertures are proven to be less resistant to plugging than wider slots for both WWS and slotted liner. Accumulation of the fines close to screen causes significant pore plugging, when conservative aperture sizes were used for both WWS and slotted liner. On the other hand, using the coupon with larger aperture size than the industry practice, resulted in excessive sanding. The experiments under linear flow seems more conservative as their results show higher produced sand and lower retained permeability, in comparison to the full scaled testing under radial flow. This work discusses the significance, procedure, challenges and early results of full-scale physical modeling of SAS in thermal operation. It also provides an insight into the fluid flow, fines migration, clogging and bridging in the vicinity of sand screens.

Coring is a considerably costly drilling operation, but vital to retrieve valuable sources of ground-truth data in the oil and gas industry. To justify the high cost of this operation, essentially, cores should not undergo jamming and mechanical damage. Core jamming not only indicates an unprecedented termination of the operation, but also causes severe damage to the core column already taken in the barrel. This means that the cores cannot be retrieved with sufficient key performance indicators (KPIs); thus, it would not reliably represent reservoir properties. Reaching this significant target can be ensured not only by proper design, but also by online monitoring and investigation of the drilling parameters. This investigation predicated on several case studies in the Middle East to identify the effect of imperfect decisions made by the driller. Based on the experience and observations, the paper provides practical recommendations to alleviate the impact of such negative actions. The drilling parameters observed in the mud logging data of six coring case studies (of several runs from three wells in carbonate reservoirs) were investigated at the depth interval just prior to jamming occurrence. These parameters consist of rate of penetration (ROP), torque, weight on the bit (WOB), rotary speed (revolutions per minute, RPM), circulation rate, and standpipe pressure (SPP). In this work, a main cause of the core jamming occurrences is discussed; that is, the improper drilling parameters application, as mismanaged by the driller. Finally, as indications of jamming, sudden variations of the drilling parameters at the specified depth were investigated. Such study can contributeto the better monitoring for future coring operations. Based on the observations in six case studies in three wells , WOB was identified as the most significant reason causing core jamming; that is, jamming occurred when the WOB was not steadily maintained on the bit probably due to the driller’s inexperience, shift change, etc. For monitoring, torque decrease, ROP decrease, and SPP variation or decrease (following initial increases) were identified as indications of core jamming. Torque showed to be a significant parameter forjamming detection when it decreases or its trend becomes completely straight, i.e., without any variations, indicating that the core head may not be in contact with the formation. Next, drilling issues during coring (such as pump failure) can contribute to subsequent jamming. The case studies in this paper provide several observations and indications of core jamming occurrences in a limestone reservoir which can be attributed to non-optimized drilling parameters. The paper also provides several practical recommendations and measures to prevent core jamming and core damage.

Calcium-based brines, principally calcium chloride and calcium bromide, find widespread use as completion fluids and base fluids for reservoir drill-in fluids (RDF). The high ionic strength of these brines, combined with the chemical compatibility issues inherent with divalent ions, such as calcium, makes identifying additives for developing functional fluids challenging. While additives, such as hydroxyethyl cellulose, can provide viscosity to calcium brines, imparting the suspension properties needed for the transport of solid bridging agents or drill cuttings can be particularly problematic in divalent brines. Even the widely used and potent suspension agent, xanthan gum, in addition to being difficult to degrade, suffers from gelation and precipitation under certain conditions in high-calcium environments. In this study, nanocellulose, which has previously shown promise as a suspension additive in freshwater and low-salinity brines, was evaluated in high-density brine fluids. Extensive laboratory evaluation of the commercially sourced nanocellulose was conducted in sodium chloride, calcium chloride, and calcium bromide brines. Rheological determinations were made of simple systems containing only brine plus the novel additive, as well as fully formulated RDF containing the additive with sized calcium carbonate bridging solids, alkalinity, and filtration control additives. This data was compared before and after aging at various temperatures and was further compared to other biopolymers that are used today in divalent brines. Stability of the fluids and the capability of the formulated fluids to suspend solids were also examined. Fluid-loss control of full formulations was compared under API conditions. Single-phase return permeability studies were conducted. While results in sodium brines were mixed, nanocellulose was shown to outperform existing biomaterials in calcium brines. Nanocellulose was shown to be readily hydrated in the challenging high-density divalent environment and provided superior suspension to currently used fluid components at similar concentrations. Rheological performance of nanocellulose was found to be synergistic with bridging solids. In one particularly interesting example, it was also shown to complement a synthetic polymer in a high-temperature calcium bromide application. Nanocellulose provides superior rheological performance and reduced formation damage potential compared to conventional materials in difficult high-density calcium chloride and bromide brines. The improved rheological profile and enhanced thermal stability of fluids formulated with nanocellulose, combined with a greater diversity of removal options, can facilitate expansion of the utility of calcium-based brines in well construction and completion applications.

Challenges of water shut-off, which is categorized under conformance control, are nowadays common in the oil and gas industry. The excessive water quantities produced from oil reservoirs can make the production process economically infeasible. The target of water shut-off process is plugging fractures or high permeability zones to decrease water cuts. Polyacrylamide tert-butyle Acrylate (PAtBA) is used for such applications. Silica (silicon dioxide) has been found to have a strengthening effect as well as it enhances the thermal and mechanical stability of the system. The objective of this study is to introduce nanosilica to reinforce PAtBA crosslinked by polyethyleneimine (PEI) and chromium Acetate (CrAc 3 ) for low and high temperature conformance control applications. In this study, different ratios of polymer to crosslinker were investigated to choose the optimum combination. Then, nanosilica (NS) with different sizes (20, 50 and 85 nm) was added to the polymeric formulation with the inorganic crosslinker (CrAc 3 ) to study the effect of silica content and size on gel strength. While, the reinforcement of the organically crosslinked gels with PEI was accomplished at 130°C. Evaluation of different systems was based on testing the rheological behavior of the mature gel based on the final storage modulus (G′). Differential scanning calorimeter (DSC) technique was also employed to understand the nature of chemical interaction between the various chemicals. The investigation reveals that PatBA:CrAc 3 of 9:0.5 is the optimum ratio producing the most strong gel. Silica with the size of 20 nm has produced the strongest gel by increasing the storage modulus by more than 150 %. At high temperature (130°C), 50 nm silica with PAtBA/PEI showed the highest storage modules compared to other sizes. DSC investigation discloses that silica is an inert and has no effect on the gelation reactions. Thus, silica has physical interactions with the polymer in the form of hydrogen bonding which enhances the strength of the gel in comparison with silica-free gels. Therefore, this study introduces a new polymeric formulation that serves as a water shut-off agent for reservoirs at low and high temperatures. The formulation that consists of PAtBA, CrAc 3 and NS makes the system more stable and gives it more resistivity toward high shears. Whereas higher gel strength was achieved when PAtBA/PEI/NS was used at high temperatures.

A porous media chemical delivery system has been developed which allows the release of various chemistries at a controlled rate, over long periods of time. This delivery system is able to replace a portion of the proppant used in gravel packing and fracturing, as well as an additive during acid stimulation. The placement of the delivery system in this manner allows for increased efficiency and elimination of operational issues associated with alternative treatments. Several case histories are presented over multiple basins. These case histories outline the versatility of this chemical delivery system by highlighting its use in different environments. Successful deployment in a variety of fluid systems including seawater based cross-linked gel, slick water, and acid are also presented. Other design factors such as temperature, produced water salinity, scale type, stress on proppant, and produced water rate are discussed. The incorporation of all these factors has yielded design volumes varying from 0.5% to 40% of the proppant/gravel pack, depending on the inhibition duration (time / produced water volume) desired. Results presented in this paper include successful scale inhibition for multiple years, include over 4 years with one application. Also highlighted are examples of inhibition in both conventional and unconventional reservoirs, as well as both onshore and offshore, and both North America and internationally. This paper will be beneficial for production engineers who desire a cost effective solution to deploy production assurance chemicals in a one-time treatment resulting in a multi-year solution.

Hydrochloric acid (HCl) is the acid of choice for acidizing operations in most carbonate formations and is the base acid commonly paired with others such as hydrofluoric (HF) in most sandstone applications. However, high dissolving power, high corrosion rate, lack of penetration, and sludging tendency coupled with high temperature can make HCl a poor choice. Alternatively, weaker and less corrosive chemicals such as organic acids can be used instead of HCl to avoid these issues. The objective of this paper is to provide an intensive review on recent advancements, technology, and problems associated with organic acids. The paper focuses on formic, acetic, citric, and lactic acids. This review includes various laboratory evaluation tests and field cases which outline the usage of organic acids for formation damage removal and dissolution. Rotating disk apparatus results were reviewed to determine the kinetics for acid dissolution of different minerals. Additional results were collected from solubility, corrosion, core-flooding, Inductively Coupled Plasma (ICP), X-Ray Diffraction (XRD), and Scanning Electron Microscope Diffraction (SEM) tests. Due to their retardation performance, organic acids have been used along with mineral acids or as a stand-alone solution for high-temperature applications. However, the main drawback of these acids is the solubility of reaction product salts. In terms of conducting dominant wormhole tests and low corrosion rating, organic acids with low concentrations show good results. Organic acids have also been utilized in other applications. For instance, formic acid is used as an intensifier to reduce the corrosion rate due to HCl in high-temperature operations. Acetic and lactic acids can be used to dissolve drilling mud filter cakes. Citric acid is commonly used as an iron sequestering agent. This paper shows organic acid advances, limitations, and applications in oil and gas operations, specifically, in acidizing jobs. The paper differentiates and closes the gap between various organic acid applications along with providing researchers an intensive guide for present and future research.

Loss circulation encountered in highly fractured formations, depleted reservoir, or HP/HT intervals is the root cause of many problems plaguing the oil and gas sector for many years. High pore pressure narrows the window of safe drilling, while in depleted reservoir fracture pressure is remarkably reduced, which may lead to a lower pressure-bearing capacity. Therefore, a proper predrill wellbore strengthening strategy is needed to anticipate wellbore issues and design drilling fluids that strengthen unstable formations. This study benefits from the successful applications of polymers in water shut-off. Whereas polymers are used to entirely plugs high water productive zones, the flowing polymer-based mud (PBM) is proposed and evaluated to enhance wellbore strengthening. Based on the API drilling fluids testing procedures, varied polyacrylamide/polyethyleneimine PAM/PEI systems were tested and ammonium chloride (NH 4 Cl) is added as a retarder to control gelling time as need. Base fluid formulated with PAM/PEI was optimized to attain the desired rheological properties. Weighting and other commercial essential additives were also added, and the formula is tested for rheology, stability, and sealing efficacy. Our proposed PBM formula with proper concentration of polymer in water and optimized PAM to PEI ratio is found to be highly competitive in comparison with the conventional methods of loss circulation prevention and wellbore strengthening techniques. This paper introduces an innovative design for a flowing polymer-based mud (PBM) for wellbore strengthening and provides wide-range of assessment. Moreover, the essential rheological characteristics revealed in this study for several PAM/PEI mud systems under various conditions can set the stage for wide application of these muds globally where tremendous reduction in drilling non-productive time (NPT) can be achieved.

Radial Jet Drilling (RJD) is an unconventional drilling technique using the jet energy of high velocity fluids to drill laterals into the reservoir formation as an alternative to the traditional stimulation technique. In this subject case study, the productivity index in a Middle Eastern well had dramatically declined due to the excessive observed bottomhole pressures. In order to improve the production conditions, a workover operation was recommended using the state-of-the-art RJD technique. The paper explains the stepwise job procedure in the drilling well plan and operations. The production conditions were compared prior to and following the RJD. Finally, the reasons for the limited success of the operation and the lessons learned for guarantying future jobs success are provided. For the RJD perforation in the well, two assembly runs were required: 1) running the RJD assembly consisting of 5/8-in drill bit, the mud motor and the coiled tubing pipe through the drill pipe, in order to open the window in the casing, and 2) running the jet nozzle assembly (no rotation) below the coiled tubing pipe in order to drill into the formation and extend the laterals to the projected lateral depth. Following the review of these procedures and operations, the paper makes a comparison between the plan and the real experience and provides the reasons for the discrepancies. The number of 14 lateral holes (six holes of 131 ft(40 m) lateral depth and eight holes of 65 ft(20 m) lateral depth) with the aperture size of 0.25 inch, were planned to be drilled by RJD. In practice, the number of only eight laterals of different length ranging 34–65 ft(9–20 m), were drilled due to improper design and operational challenges. Comparing the production conditions following the workover with the previous production conditions, a productivity enhancement of 50% was observed with RJD drilling. However, the operation had several drawbacks: the number of the drilled laterals was less than planned, their penetrated length of the laterals was lower than the planned, and the duration of the well drilling was also greater than the planned rig time. Therefore, the operations was a limited success overall. This is attributed to the smaller coiled-tubing size selected, the performance of the jet nozzle used, and the inexperience of the personnel, among other factors. The paper provides the dos and don'ts of RJD, as the first application of RJD in this field and the lessons learned from the field practice, future wells can be drilled with great enough number of laterals, their penetration length and lower cost. Therefore, the planned well productivity would be further enhanced, thereby, full success from the application of the RJD technique can be achieved.

Reservoir Conformance Control (RCC) methods may significantly improve IOR/EOR technologies through reduced water production and profile correction. In the past decades, polymer gel methods were predominantly applied with these goals. However, recently the silicates in oilfields and microemulsions in gas fields are highly appreciated by the operators due to their outstanding features and environmental friendly character. That fact is well demonstrated by more than 140 jobs carried out in Hungary, Serbia, and Oman. Although, the statistical data of these projects are attractive (75% technical and 55% economic success), probably much higher profitability could be attained if not underdosing but optimal amount of chemicals were applied to avoid deterioration of well performance (well killing in extreme case). Unfortunately, overdosing might be often realistic because of limited information on wells to be treated. Consequently, developing any water shutoff methods must comprise techniques, which must be used to rehabilitate the productivity, permeability, injectivity. That question is practically not discussed in the literature. Concerning the barrier formation kinetics and processes, the different methods can be subdivided into two groups: reversible and irreversible gelation techniques. The in-situ formation of polymer gels, whatever its types are, represent the latter one, viz. detrimental effect of chemical overdosing is hard to control even by strong oxidative agents. In contrast, the silicate methods using both external and internal pH control, the hard gel formed after placement, the formation damage can be mitigated by injection of strong alkaline solutions. Similarly, the microemulsion treatment based on phase inversion under reservoir conditions, the barrier (with 5000-10000 cP viscosity) can be disintegrated with post-injection of special organic solvents. These phenomena and processes are addressed with bulk phase studies and flow tests in sandstone cores. Independent parameters of these tests were the type of chemicals, concentration, temperature, and reaction time. The experimental findings clearly demonstrate that the silicate lamps can be completely dissolved in bulk phase, and the detrimental effect in porous cores can be mitigated by 60-70% improvement of permeability in case of overdosing chemical treatments. Similarly, even more favorable data characterized the disintegration of microemulsion barriers using bulk and flow tests. Special advantages of these mitigation procedure are that environmentally friendly chemicals are used for alleviation of the unintended formation damage. The experimental results proved that the different silicate and microemulsion methods are based on reversible barrier formation. Recognizing that fact, the design of treatment offers more engineering freedom to use not minimum, but optimum chemical load in treatments without jeopardizing the undersigned formation damage. Nevertheless, this happens, the operator has appropriate technology to eliminate the detrimental effects.

Production of heavy oil reservoirs are increasing due to the limitation in conventional resources. Despite the availability of different technologies and methods for recovery and enhancing the oil production from heavy oil reservoirs, we need to consider the oil production from these reservoirs with their particular rock and fluid chemical characteristics to prevent serious formation damage during drilling the reservoir. Heavy oil is intend to build strong microemulsions that blocks the reservoir pores. Unfortunately, this concept is missed and the heavy oil properties and its viscosity are considered as the main problems. This paper studies the formation damage and mitigation in heavy oil reservoirs. Drilling fluid is the first non-indigenous fluid to contact the formation and thus, it provides the first opportunity for causing permeability damage. The key point in formation damage control is to minimize the invasion zone into the reservoir section. Controlling the chemical reactions between invaded fluid type and heavy oil along with the changes in rock properties plays an important role in emulsion blocking which is the main cause of formation damage in these reservoirs. In addition, we need to consider other parameters such as lithology and shale dispersant which can be the other source of damage to plug the porous media. Both Laboratory pilot tests and field application proves the effect and performance of drill-in-fluid in the heavy oil reservoirs. The designed high performance reservoir compatible drilling fluid replaced oil based mud which reduced formation damage by keeping the production index at acceptable and higher level comparing to previously drilled wells. Furthermore, the paper discusses the designed criteria including formulation, properties and applications of the fluid in detail by comparing lab and field data to prove the effect of Drill-in-Fluid effect on the well production performance. It was observed that the high performance, reservoir compatible drilling fluid system, successfully minimized formation damage by minimizing fluid loss invasion into the reservoir comparing with conventional OBM with lower skin factor. This recorded a higher productivity index up to 10 times which is a unique achievement without stimulation. The oil production rate of the nominated well increased more than that of the nearby wells.

High molecular weight polyacrylamide polymers have been used for many years in water floods for enhanced oil recovery (EOR) and as friction reducers in hydraulic fracturing. More recently, so called "high viscosity" versions of these polymers are being used in fracturing operations for friction reduction and also for fracture creation and proppant transport ( Hu, 2018 ). These polymers have more complex viscous properties than materials such as guar gum or cellulose. In addition to the typical shear thinning behavior (shear viscosity), they also may have extensional viscosity thickening in convergent geometries. Separating and quantifying these properties for polyacrylamide polymers is difficult but is needed to predict their behavior not only for flow in porous media but for slot flow in hydraulic fracturing applications. Extensional viscosity in polyacrylamide polymers may be generated in a flow field that experiences a sudden change in geometry such as a contraction. The elongational flow triggers a transition in the conformation of the molecule from a coiled to a stretched state. This conformation change can result in a sudden change in resistance to flow of several magnitudes. Screen-factor measurement used in determining the resistance factor for polymers in EOR applications have been shown to have components of both shear thinning viscosity and extensional viscosity ( Lim, 1986 ). A technique has been developed using contraction flow which can separate shear viscosity from apparent extensional viscosity. The contraction flow technique is useful in determining the effect on the extensional viscosity as a result of changes in molecular weight, copolymer composition, salt effects and shear degradation of polyacrylamide polymers. Examples are given which illustrate how the results are quite useful in the selection of appropriate polymers for fracturing or water flood operations. While the extensional properties are known and the effects of the change in extensional viscosity have been better defined for flow in porous media, the definition and change in these properties have not previously been well defined for fracturing applications. Particularly, the duration of the extensional viscosity change and the effect of extensional viscosity on proppant transport and fracture geometry have not been determined.

A novel branched synthetic polymer capable of changing the relative permeability of water and oil in a formation was developed. The new polymer has the capacity to anchor to the sandstone formation, allowing it to endure production fluid flow. Thermal aging tests were conducted to evaluate the thermal stability. Gravity column tests were established as a screening method to evaluate the polymer's capacity to impair water flow and to anchor to the formation. Laboratory core flow tests were conducted using sandstone cores plugs with an air permeability of 0.8 to 5 Darcies at 200°F. The polymer was evaluated as a near wellbore treatment and as a far field treatment by altering the injection direction of the polymer slug. Results indicate that the polymer can reduce the permeability to water without significantly impairing the permeability to oil. The regain relative water permeability was less than 20% after the injection of a relative permeability modifier (RPM) polymer. The subsequent regain relative oil permeability was above 75% and the regain relative water permeability was less than 30% after the oil injection. Results also showed that the RPM polymer had similar performance regardless of the injection direction used. Moreover, pre-flushing the core with mutual solvent and surfactants before the polymer treatment did not have a significant effect on the performance of the polymer. The capacity to selectively modify the water permeability makes it feasible to use this polymer in a near wellbore or in a far field treatment to reduce excessive water production. Moreover, the polymer can be applied without the use of a mutual solvent and surfactants, thereby reducing treatment costs.

This paper highlights the new drilling and completion technologies used in the delivery of the company’s first successful horizontal open hole gravel pack (OHGP) in the deep-water Gulf of Mexico (GoM). The well was drilled and completed with well performance exceeding the planned objectives. A new drilling fluid system was needed to address the high depletion, minimize formation damage, and manage the wellbore stability challenges associated with depleted horizontal drilling stress anisotropy. A brine-based system inclusive of a reservoir drill-in fluid (RDIF), solids free screen running pill, and displacement push pill, were qualified. Managed pressure drilling (MPD) was employed to manage the drilling of depleted sands, and managed pressure cementing (MPC) was used for cementing across narrow frac gradient (FG) windows, a new application for the company. New real time drilling surveillance was also applied to allow for trajectory optimization and maximining the open hole (OH) length. For the completion, a new high temperature gravel pack (GP) carrier fluid was developed to meet the high reservoir temperature and pressure requirements. This GP fluid was also designed to break on surface using an optimized breaker system, allowing for full capture with zero discharge. The sandface completion system included a new to GoM shunted wire wrap screen (WWS), y-manifold, and new lower completion hardware including an anti-swab GP service tool. New completion open hole displacement and GP procedures, to include a new skid-based GP pumping technique, were also implemented successfully.

When used for running sand control screens, low-solids, oil-based completion fluids (LSOBCF) maintain reservoir wellbore stability and integrity while minimizing the potential risks of losses, screen plugging, completion damage, and productivity impairment. Until now, using LSOBCF as a screen running fluid (SRF) has been limited by fluid density. The design, qualification, and first deployment of an LSOBCF that incorporates a newly developed, high-density brine as the internal phase to extend the density limit is discussed. The following parameters were examined as part of the preliminary qualification: rheology performance, long-term stability, fluid loss (filter-cake repair capability), reservoir fluid and drill-in fluid (RDIF) compatibility tests, emulsion breaking test, production screen test (PST) on 275 µm screen, crystallization temperature [true crystallization temperature (TCT) and pressurized crystallization temperature (PCT)], and corrosion rate. The fluid was then tested for formation and completion damage performance, where the high-density, brine-based LSOBCF exhibited minimally damaging behavior in the core-flow tests. As a result of the positive observations made during these wide-ranging laboratory tests, this new high density-based brine was deemed as a good candidate in an LSOBCF for high-density SRF applications. Viable LSOBCF with densities up to 1.50 SG have been designed. This paper details the design and field application of a 1.45 SG LSOBCF. Calcium bromide (CaBr 2 ) brine is commonly used during the discontinuous phase for LSOBCF applications that require fluid densities up to 1.38 SG. For higher density requirements, LSOBCF use a cesium formate brine as a discontinuous phase. Using the new developed brine in the discontinuous phase provides viable LSOBCF up to 1.50 SG. The base brine has a good environmental rating, is pH neutral, and provides improved safety during low-temperature/high-pressure conditions. As a standalone fluid, the new brine can achieve densities up to 1.80 SG, with acceptable TCT and PCT values for North Sea applications without using zinc or formate-based brines. After laboratory qualification, the final fluid formulation was deployed on a dual lateral oil producer well with 9.5 in. horizontal reservoir section lengths of 2315 and 1696 m. After drilling the sections using an engineered low equivalent circulating density (ECD) oil-based RDIF (OB RDIF), each section was sequentially displaced to 1.45 SG LSOBCF. The lower completion, consisting of 5.5 in. screens equipped with autonomous inflow control devices (AICD) and swellable packers, was successfully run to bottom without significant issues. The field application demonstrated evident operational efficiency gains. The positive pre-deployment formation response test (FRT) results have been verified by well productivity data. The process to qualify the brine for first-use application in LSOBCF is described, and laboratory testing (including FRT), mixing and logistical considerations, field execution, and well productivity are discussed.

A good knowledge of foam hydraulics and cuttings transport (hole cleaning) is essential for successful applications of foam drilling technology in horizontal wells. Estimating local fluid velocity in a partially blocked eccentric annulus (due to cuttings) is a challenge; so, a new analytical method of calculating local stress and velocity (near cuttings-bed in annulus) in an eccentric annular flow is derived which makes it possible to estimate the bed height for foam drilling in horizontal wells. Therefore, a new equation for local velocity (critical velocity) to initiate particle movement is used in order to predict the bed-height profile in a build-up or horizontal section of wellbore. This investigation also focuses on understanding the effects of drilling parameters on bed height and cuttings concentration. A new transient wellbore hydraulics and cuttings transport model has been developed using the finite difference method of continuity equations for foam and cuttings. In order to predict the cuttings bed formation in horizontal wells, a mechanistic hole-cleaning model consisting of two layers has been utilized. The model is based on torque balance for a particle on the surface of a bed. In addition, a new model has been formulated for the local shear stress by modeling the eccentric annular flow as the infinite number of concentric annuli with variable outer radius. Similarly, using the narrow slot-approximation technique, a local velocity profile has been determined analytically in the eccentric annulus to be applied in the torque balance equations. Subsequently, model predictions of bed height were compared with published experimental data and the model is fine-tuned to minimize discrepancies. Results show the cuttings bed front transitions through the annulus along the build-up and horizontal sections. Model predictions showed a good match with experimental results for concentric horizontal annulus except at higher polymer concentrations (greater than 0.25%). The simulation results show that bed height and cuttings concentration are quite sensitive to the changes in surface foam injection rates and back-pressure, thereby can be best optimized by properly adjusting these input parameters. The results also suggest that hole-cleaning is a function of inclination. The bed height increases with increase in inclination angle until a critical angle of 90°-φ (φ is the angle of repose) after which, it reduces.

Hydroxypropyl guar (HPG) fluid, which is widely used in San Jorge Basin due to it is inexpensive and able to carry high concentration proppants, has more residue to damage matrix. As the permeability of tuffstone is very low, fracturing fluid that are low-damaging to the proppant pack and formation are becoming important. This paper presents the development of a low damage fracturing fluid instead of HPG and the results of successful field applications. This clean fracturing fluid uses a low-residue polymer crosslinked with zirconium having a pH of less than 10 to minimize damage and residue encountered using other fluids. The fluid was tested for rheological properties and retained permeability which was used to evaluate the compatibility of two types of fracturing fluids with formation cores at reservoir temperature. The use of regain permeability was evaluated fluids. In addition, broken fluids were tested to figure out the amount of residue. The clean fracturing fluid was expected to generate low damaging effects on tuffstone in order to increase reservoir productivity. During development, the fluid remained stable for approximately 2 hours at 120°C with a gel loading of 5 kg/m 3 . The target reservoir temperature ranges from 90°C to 120°C. Additional testing optimized gel loading at 4 kg/m 3 . The viscosity of crosslink fluids after 1 hour shear was stable about 60mPa·s at 170 sec −1 , which was much lower than HGP with 200mPa·s. The fluid suspended the proppant for approximately 2 hours. Less than 120 mg/L residue concentration was formed after fluid breakdown, which was much lower than the residue generated by HPG. A regained permeability of 88% was obtained from a sandstone core, which demonstrates the low-damaging nature of the fluid. However, the regained values of HPG were below 50% that means more than half of fracture conductivity and matrix permeability surround fracture will be lost, even HPG could carry higher concentration proppant into fracture. Four vertical wells in same work area were designed and executed successfully to compare two fluids. The well stimulated by low damage fluid got very good production, which was 2-8 times of adjacent wells. This work provides critical insights into understanding the performance of using clean fracturing fluid to mitigate formation damage in tight formations. It is an excellent candidate for fracturing operations and can help operators maintain low costs per barrel of oil equivalent.

Oil production in the fractured reservoirs shows, varying saturation values through the reservoir. This is due to the microscopic fissures and heterogeneity of the fractured environment that could not have been well swept. Higher, production/injection rates also empower the fingering effect by passing the unswept oil in the reservoir. In order to get rid of/minimize this effect, a polymer gel application is applied to fractured cores to decrease the residual oil saturation and increase the oil production. In this study, naturally and artificially fractured cores were used. Analytical calculations were done in different environments, for the experimental flow rates using cubic law under laminar flow for equivalent fracture aperture calculations for all experiments. Cubic law is verified with the fractured cores flow definition whereas not for homogeneous cores. There is a direct relation between fracture permeability with equivalent fracture aperture. The compared experiments with different environments (initially oil saturated and water saturated) in the cores, with calculations of equivalent fracture aperture and fracture permeability, showed similar results (minor deviation due to rate and saturation environment). The effect of polymer gel conformance to increase recovery by decreasing/plugging equivalent fracture aperture was proven. The calculated fracture permeability decrease was observed with decreasing equivalent fracture aperture in the core#3, #5 and #7 respectively. A case study was prepared for Polymer Gel Injection operations in R#17 and R#18 wells. Equivalent fracture apertures were calculated analytically for the field application of polymer gel injection, verified in laboratory study. It was obviously seen that before and after the polymer gel treatments in both wells, analytical calculations for the equivalent fracture aperture, were represented with the cubic law.

Innovation continues to be a driving force within the petroleum industry, particularly in the service sector. Technological breakthroughs often differentiate winners and losers in this highly competitive environment and frequently lead to improved production and real value. Advances this century in hydraulic fracturing technologies have combined to reshape the global oil market by making tight gas and mudstone unconventional plays more viable. Conversely, technologies developed decades ago have also consistently shown new life and new applications when combined with these recent technological innovations. The successful application of a revitalized non-aqueous hydraulic fracturing fluid system, first developed in the early 90's for diesel and crude oil to tackle some of the most sensitive and technically challenging formations, is documented in this case history. A brief summary of the historical application of this fracturing fluid system and the reasons for lack of applications is included. The current application of this technology, in tandem with a new refined mineral oil based fluid system energized with CO 2 , found new life for stimulation of the multifaceted Vicksburg formation in South Texas. Vicksburg formation characterization, treatment designs and post-treatment well production performances are reviewed. A short formation evaluation and engineering analysis are also provided to help understand the formation-related challenges and working mechanisms for this fracturing fluid system. Offset wells completed with alternate technologies during the same time period were weighed against wells treated with the updated 1990's era technology. The revitalized system surpassed these comparative technologies in terms of both cumulative hydrocarbon production and decreased decline rates. This case history demonstrates not only the efficacy of the documented fracturing treatment design, but also the value in combining old and new technologies as an effective method to provide innovative solutions in challenging reservoirs.

As the development of unconventional oil and gas reservoirs, hydraulic fracturing has become a critical component. However, formation damage is always impeding the application of hydraulic fracturing. A remediation method is presented that microbes can be used to remove the guar-based fracturing fluid damage. Laboratory experiment results show the feasibility and effectiveness of this method in different reservoir temperature. This approach is based on the bio-degradation of guar gum. Guar gum degrading bacteria was isolated from the well water and identified through 16S rDNA. Apparent viscosity and average molecular weight were employed to measure the bio-degradation. The mechanism of microbial remediation of guar-based fracturing fluid damage was proved by the biodegradation of filter cake through measuring the thickness of filter cake on the filter paper. In addition, the core-flood simulation experiment was also conducted to verify the feasibility of this method. The experimental method is described in detail to permit readers to replicate all results. Three guar gum degrading bacterial strains, Bacillus aerius, Anoxybacillus rupiensis and Geobacillusstearo thermophiles , were isolated and identified. Physiological-biochemical characteristics showed that the bacteria can grow in the oil reservoir with high temperature (50~70°C). In addition, the apparent viscosity and the average molecular weight of guar gum decreased significantly after bio-degradation. It means that the fluidity of guar gum residue rises. Bacillus aerius has the fastest degradation ability from 86.5 mPa·s to about 3.0 mPa·s for 48 h with the decrease of average molecular weight from 5.19×10 5 to about 4.53×10 4 . Furtheremore, the thickness of filter cake was reduced by average 0.46 mm showing the signifiacant filter cake dissolving ability. Additionally, the permeability of sand-pack columns was restored up to 93.71% in laboratory simulation experiments. In conclusion, it is believed that the microbial treatment seems to be a new approach for remediation of guar-based fracturing fluid damage and has great potential in unconventional oil and gas development. The novelty of the new method is in the ability to remove the polymeric damage using the bacteria when the formation was damaged after hydraulic fracturing.