As part of an Equinor technical efficiency programme that was initiated in 2015 to deliver savings and improvements, bridging particles were removed from the drilling fluids of 15 wells on Oseberg Main and instead loss control material (LCM) was used, as required, in some but not all the wells. These long, horizontal wells were a combination of open hole (OH) and sand screens with and without inflow control together with cased & perforated (C&P) completions, producing from typical Brent Group sandstone formations with permeabilities varying from approximately 10 mD to Darcy sands, and which were depleted by as much as approximately 280 bars. In 2018, an extensive study was performed on these wells to determine the impact on inflow performance of drilling without bridging particles. It was realized that the 15 wells offered a worst-case scenario to study in the field rather than laboratory the significance of formation damage on well productivity. The data set generated offered a unique opportunity to challenge conventional formation damage assertions, especially for long, horizontal wells, examples of which are as follows. Formation damage reduces productivity Significant mud losses with deep penetration lead to wells with lower than expected inflow performance Bridging particles are required to prevent formation damage around the near wellbore Drilling through heavily depleted reservoirs will result in severe formation damage Excessive use of graphite in an OH reservoir section will reduce inflow performance The influence of different parameters, including loss control materials, lower completion design, loss type, mud penetration depth, dynamic overbalance while drilling, length of production interval, net to gross (NTG) and kh were considered for those wells drilled without bridging particles. One of the surprising findings was that there was no clear evidence that losses were detrimental to the productivity of these long horizontal wells, i.e. it would appear that the Brent reservoir sections, despite being depleted, were more resistant to the influence of formation damage on inflow performance than first thought. Furthermore, for this example bridging particles appear to be of less importance in the avoidance of formation damage but are important in preventing excessive increases in fluid costs due to losses. After a thorough review of all the data obtained from this study, together with the conclusions drawn, it was realized that these had direct implications for Equinor's approach to fluid qualification, and especially coreflooding. The most important conclusion that influenced this change in approach was that the long reservoir sections (approximately 1 km or more) within typical Brent heterogeneous formations appear to tolerate more formation damage without impairing the productivity index (PI). A direct consequence of this was the conclusion that more emphasis should be placed on fluid compatibility, mobility, screen plugging and stability along with particle size distribution (PSD) design while the importance of coreflooding to fluid qualification was downgraded for Brent and reservoirs of similar chacteristics. This is not to say that coreflooding will not be performed, but rather it will be targeted towards situations where the influence of formation damage on well productivity is more significant, e.g. HTHP fields where special drilling and completion fluids are required, low permeable formations without mechanical stimulation, and shallow reservoirs with low reservoir temperature. This paper will perform an evaluation of the significance of formation damage on well productivity and use this to demonstrate Equinor's revised approach to formation damage laboratory evaluation based upon field experiences.

A major operator in the Gulf of Mexico (GOM) desired to increase oil production to meet growing energy demand. To meet this challenge, the operator explored an alternate completion design to mitigate reservoir damage observed in previous producing wells and collaborated with the fluids provider to design a solution to address this concern. The design and solution ultimately applied resulted in "negative skin" with production rates far exceeding historical field rates. Additionally, the operator realized significant cost savings with this change in completion approach by eliminating traditional steps. The development field had its unique challenges with ongoing depletion, wellbore instability risks, and compartmentalization in the reservoir, making access to thinner oil reservoirs challenging to develop. The standard completion approach was to drill with a synthetic-based fluid, perforate the casing, and perform a frac-pack completion. Using technology from another region, the operator elected to change the traditional cased hole frac-pack approach to drilling horizontally through the reservoir, run production screens, and perform an open hole gravel pack completion. In the fluids design phase, the fluids provider performed hydraulics modeling and laboratory testing on multiple formulations, including brine compatibility with formation water; formation response testing; high-pressure/high-temperature (HPHT) rheology and fluid loss; static age testing for intervals of 16 hours, 3 days, and 5 days; and contamination testing with solids, synthetic-based mud, and cement. This paper discusses the methodology used in the design phase required to engineer a reservoir friendly fluid to meet the challenges faced with this complex well.

Objective/Scope The objective of this paper is to present a successful acid frac technique applied in a deep HPHT well to enhance the productivity of Marrat reservoir. Method, Procedures, Process Jurassic reservoirs in the state of Kuwait are deep, sour and tight with High-Pressure and High-Temperature (HPHT) environment. Challenging reservoir quality like low permeability, low porosity, uncertainty about some natural and induced fractures, high stress, etc limits the productivity development for this reservoir. The subject well was drilled up to 16,790 ft with high-density Oil Base Mud (OBM), upto 17 ppg, targeting Marrat formation to prove hydrocarbon in this area. Formation damage caused due to invasion of high-density mud, using Barite as a weighting agent, into the carbonate reservoir poses a challenge to design a proper stimulation treatment to restore the permeability and to evaluate the real reservoir potential. Since the damage caused by OBM invasion cannot be easily treated, it was decided to stimulate this reservoir either by matrix or fracture stimulation. The subject well was tested with Drill Stem Test (DST) and perforated in underbalance condition using TCP gun. Acid treatment was performed with 28% emulsified acid solutions to gain the deep wormhole penetration in order to enhance the well productivity. Pre and Post stimulation flow measurement confirmed a slight improvement in productivity. But still there is a scope for increasing productivity further more. Based on the test results, it was decided to Hydraulic Frac the Jurassic reservoir to achieve the expected potential. A detailed study was carried out to identify reservoir quality and completion challenges that limit the development of reservoir potential and to recommend remedial mechanism, acid or proppant frac, to improve the well productivity. Based on the analysis, acid frac design and procedure was established to gather data and improve productivity from Marrat reservoir. Prior to the main fracturing treatment, a data-frac was conducted to determine reservoir parameters such as fracture extension pressure, fracture closure pressure and instantaneous shut-in pressure. Based on data-frac results, acid frac was successfully executed and the well productivity was tremendously improved. Results, Observations, Conclusions High injection surface pressure of 13,800 psi and high leak-off was observed during main acid treatment due to the tight nature of the formation that resulted in low fluid efficiency and relatively short etched fracture length. Acid fracturing treatment was carried out successfully without encountering any major operational issues. The post-acid frac production results show significant improvement in productivity Index(PI) and 3-4 folds increase in production comparing to main acid treatment results. Post-frac analysis was carried out on the sustained production from the Jurassic reservoir. Novel/Additive Information Improvement in well productivity after the acid frac stimulation confirmed the well potential and supported exploration group to achieve the reserve target.

A novel approach to exploit thermal energy released from the exothermic reactions of aqueous solution of thermochemical reactants (ammonium chloride and sodium nitrite), in controlling formation damage induced by water-in-oil emulsion have been investigated. Essentially, the technology concerns raising the temperature and pressure of the formation above the kinetic stability of emulsion through the heat and pressure generated insitu from the reaction. From the batch experiments to assess the energetic of the thermochemical reaction, it was observed that the temperature of the system could be raised to ≈170 °C (from 100 °C initial temperature) and pressure of 1600 psia, under controlled conditions. A stable water-in-oil (W/O) emulsion was prepared and used as a damaging fluid. Ultimately, about 72% of the W/O emulsion was removed from the core sample by injecting 1 PV of thermochemical fluids. In addition, the pressure profile, observed during the flooding experiment, shows that no precipitation or damage was induced during the thermochemical flooding. Therefore, it is envisaged that the insitu heat generation can mitigate emulsion blockage problem, and offers advantages over the existing methods considering environmental friendliness and damage removal efficiency.

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.

The presence of residual oil or gas during fines migration in porous media greatly affects particle mobilization and capture. This paper investigates the effects of kaolinite content on fines migration and formation damage in the presence of oil residual. We carried out corefloods on engineered sand-packs that contained different percentages of kaolinite. Each core sample was subjected to brine injections varying from seawater salinity to freshwater. Measurements of the pressure drop and effluent particle size distributions were performed for each injection. It was determined that the main cause of permeability decline was pore throat straining by kaolinite. A higher decline of permeability accompanied by intensive fines production was encountered during freshwater injection. If compared with fines migration under single-phase flow, having a residual phase showed a significant decrease in formation damage and the amount of produced kaolinite. The laboratory data were matched with the analytical model for one-dimensional linear flow. A close agreement between the coreflood data and the model was obtained. The model coefficients were used for well injectivity decline prediction using a numerical one-dimensional radial injection model. The kaolinite content and the residual oil phase greatly impacted the well injectivity decline.

Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. Unscheduled events that are related to wellbore instability account for more than 10% of the drilling cost, which is estimated to one billion dollars per annual cost. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for providing a more suitable drilling fluid system for drilling operations in unconventional resources is growing. The major consequences of improper fluid selection include bit-balling, hole sloughing, and most importantly low drilling rates. This study will evaluate the effect of different inhibitive drilling fluid systems on shale drilling performance. The mud systems use in this study include cesium formate, KCl based mud systems, and a conventional water-based mud. The conventional water-based mud is used as reference fluid. An innovative HPHT drilling simulator is used to perform real-time drilling operations on cylindrical shale core samples obtained from the Tuscaloosa Marine Shale (TMS). The process involved simulating real-time drilling operation at downhole conditions where different fluids served as drilling fluid. A comparative analysis of the impact of each drilling fluid systems on the drilling performance as then performed. The analysis focused on drilling parameters such as rate of penetration, torque, and friction factor during drilling. This paper evaluates the compatibility between different fluid systems and shale formations. The paper also provides an overview of the effect of the inhibitive mud systems on drilling performance. The inhibitive muds systems (KCl based fluids and cesium formate) provided improved drilling performance compared to conventional water-based mud.

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.

Formation damage can occur in the vicinity of the wellbore or far field in the reservoir. Organic and inorganic deposition such as asphaltene, paraffin, iron sulfide, barium sulfate and calcium carbonate are the most commonly encountered scale types of damage. Accidental interactions between the completion kill fluid after the perforation or the drilling fluid while drilling through the target zone are also major causes. The decline of well productivity is the first indication of formation damage and can be used as a determining factor of its severity. Therefore, the type of damage, the mechanisms, and controls need to be analyzed and predicted. This paper presents a detailed and comprehensive review of formation damage including both the external and internal types and the far field and near-wellbore damage. Damage can be identified by observing changes mainly in the well productivity; however, it can be also observed using retrieved equipment such as logging tools and downhole pumps or due to the restricted entry of completion equipment such as inflow control devices (ICDs). The impact of well configuration on the formation damage and the remedy afterwards is also discussed in details. The present study provides a solution and control criteria for the formation damage and a comprehensive mechanistic modeling is proposed. The model is applied by coupling reservoir modeling with the wellbore conservation equations through the pressure. The effect of horizontal laterals is included by developing three-phase transient equations to account for the flow rate change from toe to heel in the drain hole.

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.

Drilling long horizontal and multilateral wells in the oil industry helps lower the drawdown, and minimize water or gas coning, which enhances well productivity. Many of these wells are drilled using drill-in fluid (DIF), which is cleaner than conventional mud and so is considered to be less damaging to the formation. The DIF consists of polymers for building the required viscosity to transport cuttings and deposit a filter cake around the wellbore to reduce fluid loss. Most DIFs are composed of starch, cellulose or Xanthan polymers added with bridging agents of calcium carbonates and salt particles. Even though DIF causes less formation damage than conventional mud, damage to target formations can still occur. To remove formation damage caused by DIF, a new chemical technology is tested. The new chemical technology, which breaks up the coherence and integrity of the mudcake and polymer gel, was used for wellbore cleanup with very encouraging results. In addition, the chemical is also an eco-friendly, noncorrosive bio-enzyme and is naturally biodegradable. The chemical disintegrates into its natural elements (carbon, hydrogen, oxygen and nitrogen) after converting the insoluble polymers into water soluble sugars. In addition, the chemical minimizes formation of wormholes like in acid, which helps in keeping the wellbore away from getting connected to fractures/fissures. This paper highlights the technological advantage of using the enzyme based chemical and how homogenous wellbore cleanup/stimulation is achieved, leading to productivity enhancement and sustainable oil production.

The injection of oil and gas wastes produced during the exploration and production phases have been proven to be an effective technique toward achieving zero discharge. However, several challenges are associated with the injection of slurry into an underground formation. The most common challenge during waste slurry injection (WSI) is the continuous loss of well injectivity due to poor engineering design of the injection parameters for most of the current existing WSI wells. For the WSI operation, near wellbore formation damage (including the fracture damage) will be formed by the injected solids. The real time injection monitoring of the ongoing operations is important to correct any operational mistake and adjust the injection parameters in order to ensure the well longevity. The paper discusses the importance of injection monitoring and steps necessary to maintain the injectivity and perform a healthy WSI operation. Three different case studies are presented to highlight the operational mistakes that caused a significant formation damage development in injectors in Eagle Ford, Haynesville, and Permian Basin shale plays. Certain guidelines depending on the monitoring results are provided in modifying the slurry rheology, pressure, injection strategy etc. that are helpful in maintaining the injectivity. The presented case studies show that the wells with good monitoring program maintained its injectivity during the course of its operation compared to the other wells that lost its injectivity sooner. The results from different case studies are used to prepare a set of guidelines that can be used to maintain the well injectivity and extend the well life. This paper discusses the techniques that will help in eliminating and avoiding the problems leading to formation damage and well plugging during the WSI operation.

The water production from the oil wells not only increases the per barrel oil production cost but also raises environmental concerns. The use of conventional water shut-off techniques not only restricts the production of water but also reduces the oil production. The use of emulsified polymer gel system presents an efficient way for conformance control in the oil reservoirs. The emulsified polymer gel system was designed in such a way that it will separated into oleic and aqueous phase encountering higher reservoir temperature. The aqueous phase will become gel and provides the resistance towards the water flow whereas the oil phase will provide the passage to oil, towards the production well. In this research work, an emulsified polymer gel system was developed having polyacrylamide and polyethylenimine as aqueous phase and diesel as oleic phase. The organoclay Cloisite 20A was used as an emulsifier. The emulsified polymer gel system was characterized by dilution test, microscopic analysis and gel strength code. The developed emulsified polymer gel was found to be water-in-oil emulsion system, which formed rigid gel (gel strength grade-I) under reservoir temperature conditions. The thermal stability of the emulsion system was tested at 105°C. The emulsion stability index of the emulsified gel system was also calculated. To check the effectiveness of the developed emulsified gel system for conformance control, core-flooding experiment was performed at 105 °C. During the core flooding experiment, the system provides desired resistance to water flow whereas allow the diesel oil to produce with ease. This indicates that the developed emulsified polymer gel system is an effective conformance control system, which can be used in high temperature reservoirs. This research work presents a core flooding experiment study, to evaluate the performance of emulsified gel system (Pickering emulsion) for conformance control in high temperature reservoirs.

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.

This paper provides insights into the long-term production performance of a set of five HPHT wells drilled and completed with SG 2.0 cesium formate fluids across the entire sequence of gas-filled Brent Group reservoir formations of the Kvitebjørn field during the period 2004/5. Three of the wells were completed in open hole with screens and the other two with cemented and perforated liners. All of the wells cleaned up naturally during production start-up. Well logs run in the first series of wells drilled and completed with cesium formate fluids provided enhanced reservoir information indicating improved reservoir quality which translated into a 33% increase in the Hydrocarbon Pore Factor (HCPF). After a year of production from these wells a new updated reservoir evaluation, factoring in the improved reservoir quality and more reservoir volume, increased the overall Kvitebjørn recoverable gas reserves by 50% to 79.97 GSm³ of gas and 30.13 million Sm³ of condensate. As a result of this evaluation the expected recoverable reserves for the first five production wells drilled in 2004/5 rose from 32.7 GSm 3 to 48.3 GSm 3 for gas and from 12.3 MSm 3 to 14.8 MSm 3 for condensate. Apparent reductions in well productivity indices (PI) of 20-80% were measured in the first 5-7 years of production. The PI reductions could have resulted from a combination of scaling, condensate banking, reservoir compaction or even problems with the PI estimations. One of the wells with a liner completion was re-perforated twice (in 2012 and 2015) and another well with a screen completion was perforated through blocked screens in 2015, but the remaining three wells have continued to produce without intervention for 14 years. The cumulative gas production from the five wells up to October 2018 stood at 60.1 GSm 3 , which is already 24 % higher than the mean total recoverable reserves predicted in the 2006 reserves evaluation and almost double the figure anticipated in the original 2004 field development plan. The cumulative condensate production over the same time stood at 20.4 MSm 3 , which is 38 % higher than the mean total recoverable reserves predicted in the 2006 reserves evaluation and almost double the figure anticipated in the original 2004 field development plan. In laboratory formation damage tests conducted at 150°C the oil permeability of a Kvitebjørn reservoir core plug flooded with a sample of the cesium formate drilling fluid recovered from the field after use in all five wells was reduced by 65% from 29 mD to 10.2 mD. This very valuable test may now allow a retrospective evaluation of the predictive value of that particular laboratory-based return permeability test method used to assess the formation compatibility of that formate fluid twelve years ago.

A simple and effective particle-size selection program was developed to significantly reduce the amount of testing required when designing bridging solids systems for use in fluid loss control pills for gravel-pack or frac-pack applications. Applying Ideal Packing Theory (also known as the D ½ rule) and Abram's 1/3 rule with some modifications, linear plots of cumulative volume percentage of bridging particles versus the square-root of particle diameter was used to obtain optimal formulations of bridging solids in ratios that effectively bridged and sealed machined, laboratory-grade, wire-wrapped screens of 2.5-inch. o.d., 2-inch i.d., and 0.25-inch thickness. High-pressure/high-temperature (HP/HT) filtration testing of optimized screen-specific formulations of calcium bromide-based TETRA SmartSeal™ pills was completed using 6, 8, 10 and 12 gauge screens under 500 psi pressure and 215°F temperature conditions over a 72-hour period. The results show that low-permeability, well-packed filter cakes of thickness less than 2 mm were formed on the screens, allowing minimal fluid passage, with average spurt volume less than 6 mL, average 30-minute filtrate volume less than 8 mL, and maximum 72-hour filtrate volume less than 25 mL.

In tight reservoirs, the invasion of water-based fracturing fluids into the rock matrix may reduce hydrocarbon relative permeability and consequently oil production rate. This paper aims at investigating the change in oil effective-permeability ( k o e f ) during the flowback processes after hydraulic fracturing operations. We perform a series of core flooding tests on core plugs collected from Midale tight carbonate reservoir to simulate fracturing fluid leak-off and flowback processes. First, we clean, saturate the plugs with reservoir brine and filtered oil, then age them in oil for 14 days under reservoir conditions (P=2500 psig and T=60°C) to restore reservoir conditions and define baseline k o e f . Second, we measure k o e f before and after fluid leak-off for (i) different fracturing fluids (i.e. freshwater and a mixture of three nonionic surfactants), and (ii) different shut-in times (3 and 14 days). The results show that regained permeability after the fracturing fluid leak-off in a high-permeability plug indicates a two-fold increase (from 1.4 to 0.7 md) compared to the freshwater case. The improved k o e f in this high-permeability plug is due to the effects of interfacial tension reduction (from 26.07 mN/m for freshwater-oil to 5.79 mN/m for fracturing fluid-oil) by surfactants. In terms of shut-in times, k o e f measured after 3- and 14-day shut-in times in high permeability plugs indicate a reduction of 5.71% to 17.98% compared to the baseline values. This means that there is no significant change in regained permeability by increasing the shut-in time from 3 to 14 days. We also observe that k o e f of a low-permeability plug show 29% and 65% higher than corresponding baseline values after 3- and 14-day shut-in periods, respectively. The regained permeability strongly depends on porosity, permeability and irreducible water saturation of the plugs.

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.

Water injection wells were planned to provide pressure support to oil producers in two North Sea fields (Field A and Field B). For both fields, water-based drilling fluid was selected to drill the reservoir section. The average permeability of the first field is 1000 mD and the second field is 50-100 mD. A laboratory study was commissioned to evaluate and optimize filter cake breaker systems for use in water injectors to efficiently remove external and internal filter cake in order to attain matrix injection without the need for backflow to clean up the sand face. A time-delayed filter cake breaker system was chosen for evaluation as part of the study. Laboratory-scale formation damage tests indicated significant loss of injectivity, potentially due to deep invasion of xanthan polymers in core plugs along with incomplete dissolution of calcium carbonate from the filter cake. An enzyme package designed to degrade xanthan was included in the revised breaker solution and an improvement in injectivity was recorded. Further adjustments were made to the breaker formulation to optimize performance for density range, corrosion mitigation and dissolution of calcium carbonate, including allowance for the impact of the addition of lubricant to the drilling fluid. Following an extensive and detailed study, a much greater understanding of the design, evaluation and field engineering aspects of chemical breakers has been gained. The recommendations from the study have recently been applied to injection wells on both fields. This paper describes the test procedures adopted for evaluating the various filter cake breaker formulations and the work conducted to develop the systems to be ready for field use. The challenge and consequences around scaling up laboratory results to field conditions is particularly acknowledged. Field results are presented, highlighting both the importance of critical design issues and applied learnings for a successful outcome.