The challenge in many permeable water sensitive subhydrostatic reservoirs is to avoid the loss of completion fluid when completing or working over wells. It is not unusual to lose up to 1,000 bbl of completion fluid, resulting in a 20% to 50% reduction in production. Several different approaches have been used to prevent these losses. The most common is viscous fluid-loss control pills with sized particulates, such as calcium carbonate, which often requires a further treatment to remove the solids. An alternative is a solids-free crosslinked viscous polymer pill, which must be spotted and kept in position across the reservoir prior to it crosslinking. To overcome the limitation of conventional fluid-loss control pills, a low-viscosity system was developed. The system is composed of a viscous disproportionate permeability modifier (VDPM) with sized synthetic polymer particles and fibers, which, with time and temperature, degrade into organic acids. The VDPM reduces the effective permeability to the water-based fluids, and the sized particles create an impermeable filter cake. When the particles degrade, the organic acid acts to break any remaining polymer. The system can either be bullheaded or spotted in the wellbore prior to perforating and effectively seals the formation for several days. The fluid-loss pill has been used successfully in more than 25 wells. The volume of fluid lost into the formation is often less than 1 bbl, and production is maintained after the workover. The technique has made it possible to selectively stimulate new intervals or recomplete wells with an average increase of more than 240 BOPD, whereas, historically, a decline in production was not uncommon.

The Captain Field is situated in the outer Moray Firth in approximately 340ft water depth. The reservoirs are shallow sandstone, either sheet turbidite or channel sands. The oil is relatively viscous and is drained using long horizontal wells. The reservoir is sub hydrostatic and uses either electrical or hydraulic submersiblepumps for artificial lift. Produced water re-injection supplemented by the field aquifer is used for voidage replacement and to maintain reservoir pressure above bubble point. The water injectors are long horizontal wells with one injector supporting a number of producers. The sand is unconsolidated and injectors are generally completed with stand-alone screens. Since drilling the first injector well in 1995 there has been an evolution in drilling and completion practices and while the original wells were drilled with non-aqueous drilling fluids, current wells are drilled with water based fluids that have been optimized over the years. This has been an iterative process with the aim of reducing formation damage and increasing baseline injectivity. Screen type and stimulation techniques have also changed over time and later platform wells have also been flowed back to surface which tends to greatly improve the initial injectivity. This improved injectivity is critical for the success of future field development and enhanced oil recovery deployment, which initially requires drilling of new subsea injectors. However flowing a subsea injector back to a semisubmersible rig involves significant safety and operational issues, thus new methods of increasing injectivity are being sought. This paper will present the history of the Captain Field's injectors, explain the lessons learned over time and describe the ongoing studies that are being performed to better understand the damage mechanisms to ultimately eliminate the requirement for flowing back injector wells.

Most conventional fracturing fluid systems are based on guar and guar derivatives. Therefore, fracturing costs are strongly influenced by guar price. In addition, when pumped in unconventional formations, these fluid systems can cause significant formation damage due to insoluble protein components in guar. While Polyacrylamide (PAM) based copolymers are often used in unconventional formation stimulation, they are often considered to be hard to break. A possible solution that can mitigate the problems associated with the conventional fracturing fluid systems is a new fluid system based on a carefully designed synthetic polymer. The synthetic nature of the polymer translates into a stable operating cost without being impacted by market fluctuations like in the case of guar. This new synthetic polymer system is crosslinked and applied similarly to polysaccharide-based fluids. To alleviate concerns that synthetic polymer is hard to break, this polymer incorporates special linkages, periodically distributed along its backbone, to make it easily broken into small fragments with conventional oxidative breakers under downhole conditions to leave minimal formation or fracture damage. The polymer also incorporates functional groups that resist damage from water hardness. In addition, the polymer hydrates almost instantaneously and allows rapid viscosity generation and adjustment without a hydration unit, which greatly reduces footprint of hydraulic fracturing treatments. While this new polymer system can be used in slickwater hydraulic fracturing and linear gel applications, laboratory testing also showed that it can be effectively crosslinked with conventional metal crosslinkers. This paper investigates the possibility of using this new polymer as a total package to be applied throughout hybrid fracturing operations for tight formations besides using it as fracturing fluids for conventional formations. Laboratory work also investigated other applications of the new polymer such as acid gelling, acid fracturing, and diversion, to name a few. This paper presents the laboratory performance and the underlying mechanisms of the novel polymer fluid system.

Developing drilling mud technology follows the industrial needs but in the interest of reducing formation damage the object is choosing the most suitable mud. It is even more important question when the pressure and temperature in a well is high. This paper tries to make this choice easier by measuring static and dynamic filtration of drilling mud on changing temperature. Before designing a HPHT well there are two important cases which must be considered, the margin between the fracture gradient and the pore pressure is small what is critical in the design of the well and HPHT wells usually have high ECD (Equivalent Circulating Density) that leads to lost circulation problems that becomes difficult to control. The choice of accurate mud density is critical due to the narrow margin between the pore pressure and the fracture gradient. The applied mud has to stay stable under extreme temperatures and pressures and has to have optimized rheology to minimize ECD. In our presentation we will show the results and comparison of the experiments that were conducted using a dynamic HPHT filter press with core sample plugs as filters both static and dynamic conditions to determine the filtrate and thickness and composition of the filter cake. The quantity and quality of spurt loss and fluid loss was compared on different temperatures and core samples. Filtration rate is one of the most complex mud properties because it may be influenced by almost any change in other properties-rheology, composition and particle size distribution-and in this way its effect on formation damage. At elevated temperatures these effects are more significant.

Drilling depleted reservoirs can present many challenges from a drilling, completion and production perspective. Formation damage due to increased overbalance for example, is well documented as a particular concern. But could we see some drilling benefit from increased formation damage at higher overbalance? This paper will outline experience in drilling depleted reservoirs and discuss the impact of formation damage on well productivity, injectivity and drilling performance. In several examples, the benefits of formation damage outweigh the deficits and we propose a planned approach for future wells in depleted reservoirs. Formation damage is measured in the same way as for assessment of the productivity or injectivity impact but the data is applied to a different challenge. The additional pressure drop in the near wellbore area as a result of formation damage can protect the reservoir and minimise fracture propagation. Whilst formation damage can be important in depleted reservoirs it is largely irrelevant if wells cannot be drilled. With the method proposed wells can be planned, drilled, completed and produced (or injected). The paper proposes better understanding of the impact of formation damage in order to enable drilling, completion and development of depleted reservoirs or intervals and proposes a new methodology to use formation damage as part of a well planning workflow.

The Troll field in Norway is a large gas field with a thin oil column. The thin oil column requires the wells to be drilled as long horizontal oil producers and development of the field has relied entirely on water based drilling fluids. As the pressure in the reservoir is depleting there is a requirement to reduce the density of the drilling fluid used to avoid losses. The latest development that is described in this paper is the design and implementation of a reservoir drill-in fluid with a maximum density of 1,07 SG, which at the same time maintains all the technical requirements necessary to avoid formation damage. The laboratory evaluation and verification was performed together with the operator to ensure no operational problems arose from changing to a new system. New technology was introduced to allow for clay inhibition without the use of salt to reduce the density of the base fluid. Bridging was optimized to match the requirements for the high permeability reservoir with minimum concentrations of solids. Product selection was driven by the need to ensure minimum formation damage. The initial field trial and the resulting implementation on subsequent wells and different rigs are described. The difference in performance related to other types drilling fluid systems is discussed. In addition, the effect of the differences in solids control equipment and storage capacity on different rigs is evaluated.

The leakage of reservoir fluids into a wellbore during perforation, workover, or other completion operations is a substantial concern, especially in high temperature wells where existing fluids utilized to mitigate reservoir fluid influx offer poor performance. To maintain the hydrostatic integrity of the wellbore during these operations, a thermally-stable, solids-free fluid loss pill has been developed. The pill is composed of synthetic polymers and cross-linkers in monovalent high-density brine. Under ambient pressure and temperature conditions, the pill flows as a viscous liquid and remains fluid for over six months. Upon exposure to elevated temperatures (200°F to 375°F), the pill cross-links to form a robust gel that can act as an appropriately-weighted, low fluid loss pill. This pill can temporarily seal the reservoir, enabling well control during completion operations. Gelled samples of the fluid loss pill have maintained integrity for up to three weeks under HTHP conditions in laboratory testing with minimal signs of collapse. Fluid loss tests at different temperatures were conducted to assess the fluid loss performance. Gel could be easily removed without a breaker by the formation pressure of the reservoir upon well completion due to the solids-free nature and lower lift-off pressures required for this particular gel. However, depending on the specific requirements for a formation, this gel could be readily destroyed with high temperature oxidative breaker systems. In such circumstances, the timing of gel removal could be completely controlled by the timing of the breaker addition. The gel was also evaluated for any formation damage issues if used in a high temperature gas reservoir by using regain permeability experiments with Berea sandstone cores. Necessary precautions were taken to eliminate the permeability impairment effects caused by the change in water saturation of the tested core. Average fluid loss in the core flooding test over 3 days at 320 °F was about 50 ml. Restoration of the Berea core permeability after the treatment exceeded 95% of the initial permeability with low lift-off pressures observed. This paper presents full laboratory data on the fluid loss performance and regain permeability of a novel thermally-stable, solids-free fluid loss gel.

Due to usual higher oil and gas production, high permeable reservoirs are considered to be forgiving and to be able to hold up very well against formation damage induced by any solids and liquids, so these reservoirs have not deserved a fair share of that attention. In fact, any formation damage can inevitably alter the permeability of the porous media and adversely affect oil recovery to different degrees, and the damage is more deadly to horizontal well. Triassic reservoir with the maximum permeability of more than 2 Darcy and the maximum throat sizes of more than 100 μm in the Tarim Basin provides us with a perfect example. Horizontal well is the key technique to increase oil production in this reservoir. However, after completion, horizontal wells can not produce through natural power or gas-lift, and did not present the advantages of increasing production compared with vertical wells. The results of granularity analysis and dynamic damage evaluation experiments present that the original drill-in fluids can not protect the reservoir with permeability of more than 100 mD, while the percentage of regain permeability is less than 50%. The drilling fluids were modified by adding fibrous bridging agents instead of common spherical bridging agents to rapidly form a tight plugging zone near the wellbore that efficiently seals the large pore throats. The dynamic filtration test and the analysis of mudcake through the FEI Quanta 450 environment scanning electron microscope (ESEM) showed that the optimized drill-in fluids can form tight filter cakes, plug the pore of reservoir effectively, and enhance the percentage of regain permeability of core samples up to 90%. After the application of the new drill-in fluids, horizontal wells are in high flowing production after completion, and the wellbore quality are also improved.

Two important aspects often overlooked in the design of bridging solids packages for drilling fluids are: a) obtaining accurate particle size measurements, and b) allowing for the influence of particle attrition. This paper explores both aspects and illustrates, using field data, the challenges and positive impact on productivity (or injectivity) of getting the distribution right. Commonly-used bridging solids were sized in the laboratory by sieve analysis and laser diffraction techniques and the results compared. The two methods gave similar results for particles in the range ~ 50–500 μm, but there was a significant discrepancy for larger particles. Since sieving best reflects the functional purpose of the particles (to block pores or fractures) it is suggested that sieve analysis should be the preferred method for particles with a d90 above about 500 μm. Studies of particle grind down (attrition) showed the critical attrition parameters to be the particle type (material), the initial particle size, and the shear rate. Large particles ground down faster and to a greater extent than smaller ones. In the laboratory tests, large 1400 μm particles were found to reduce in size by up to 80% compared with only a 5% reduction in size for 300 μm sized particles over a 30 minute test period. Fluid viscosity also had an influence on attrition but particle concentration appeared to have only a marginal effect. Two field case studies are presented. These used small bridging particles for pore sealing to minimize formation damage in two drill-in fluid applications. A grind-down effect was observed in case 1 (water based mud) which used 50 μm marble particles, and so steps were taken to restore the size distribution. There was no apparent attrition effect in case 2 (oil mud) which used a mixture of smaller 20 μm marble particles and barite. Careful management of the fluids led to a successful outcome in terms of well performance in both cases.

Water production from hydrocarbon reservoirs is a serious problem in the oil industry. High water cut reduces the economic life of producing wells and costs the industry billions of dollars each year ( Curtice and Dalrymple 2004 ). Throughout the years, several techniques and chemicals have been developed to control undesired water production. The industry has developed and applied a variety of chemical systems to reduce or shut off unwanted water production. However, most of these chemical systems are often quickly categorized as environmentally damaging according to the environmental laws and regulations, particularly in the North Sea area. This means that service companies must keep pushing technology development in a more environmentally acceptable direction. The recent development of a "green," environmentally acceptable colloidal silica-based sealant system is an example of this process. This sealant system is a two-component system containing a liquid silica and an activator. The system is easy to mix and easy to pump because of its low viscosity. Once it is placed into the water-bearing zone, the system forms a stiff gel to block the flow of water. Any underdisplaced gel left in the tubing can also be easily washed out using coiled tubing (CT). The system can also be viscosified or slurried with polymer or particulates, respectively, if diversion is required in longer intervals with high permeability and pressure contrast. In addition to water and gas shutoff, this new system shows potential in other areas, such as formation consolidation, temporary gel plugs, annular barrier re-establishment, as well as stopping severe losses while drilling and recompleting. The gel-setting time can be tailored for a wide temperature range from 20 to 150°C by varying the concentration of the activator. Extensive laboratory research has been performed to develop and qualify this sealant system. Simple, static-sealed tube tests were first run to qualitatively evaluate the gel strength and gelation time. Then, gradually, the formulation was refined and rheological data was measured and collected using a Brookfield viscometer. Further, core-flooding tests were conducted both in sandpack and carbonate cores to determine the effectiveness of the system in blocking water flow. This paper describes the development of this environmentally acceptable sealant system and the qualification process including laboratory test methods and results.

It is commonly understood that a reservoir drilling fluid must be compatible with the reservoir rock, both chemically and physically. One important aspect in optimizing drilling fluid is distribution of bridging particle sizes. Appropriate particle sizes can limit fluid loss to the formation and minimize solid plugging into reservoir pores. Reservoir rocks have complicated fluid-flow systems and it is important to understand pore characteristics of the rocks including pore type, size distribution and connectivity; and, secondary changes such as dissolution and fracturing. If inter-particle pores are the dominant fluid-flow channels for the sandstone and pore distribution is relatively homogeneous, a full range of particle-size distribution of bridging material may effectively bridge all pore spaces. But for many types of sandstone, natural dissolution of feldspar, rock fragments, or carbonate material has created oversized pores. Appropriately sized particles should be used to bridge them, and smaller particles should be retained in fluids to bridge smaller pores and to improve filtercake quality. For carbonate rocks, fracturing and/or dissolution may have created large pores or fluid-flow channels. They are usually inhomogeneous in space. Their sizes vary greatly and could be up to centimeter scale. The bridging particle size distribution should be comparable to the inhomogeneous pores or channels, if practical. Differential pressure between wellbore and formation pore fluid is also a factor which influences bridging size selection. At high differential pressure, relatively large particle sizes may help limit the solids plugging into pore spaces and decrease the effect of filtercake compaction. However, a combination of pore size, fluid property, and filtercake quality considerations are needed to achieve the most effective particle size distribution.

The objective of this work is to investigate the influence of cuttings size in Casing Drilling to plug pores for fluid loss control, and thereby reducing formation damage. Historically, the emphasis of drilling operations has been to drill wells cheaply and quickly without much consideration for the resulting impact on well productivity. Formation damage occurs frequently and rapidly during drilling operations with potentially severe consequences. The Plastering Effect of Casing Drilling reduces solids and filtrate invasion, resulting in less skin damage and improved productivity. It also reduces formation damage due to cement filtrate by creating a gauged wellbore and proper casing/wellbore standoff. The Casing Drilling process grinds drill cuttings as they travel up the annulus and creates a larger particle size distribution (PSD) profile than conventional drilling operations. These finer cuttings are subsequently smeared into the wellbore face by the mechanical contact of the large diameter casing with the borehole wall. The result is a very high quality, tight, thin, almost impermeable mud cake that isolates the formation from the wellbore. Evidence shows that cement binds very well to this type of mud cake. The PSD analysis determined that the smaller size and wide range of Casing Drilling cuttings make it possible for these particles to readily adhere to the wellbore; this helps seal the pore spaces of the formation and prevent further solids and filtrate invasion. Pore throats can most effectively be plugged when the cuttings are in the proper micron size range as any possible gap between the mud and cuttings PSD can be covered by adding minimal amounts of properly sized lost circulation materials. Casing Drilling has proven to be a unique approach in mitigating formation damage due to the drilling process. One case study confirms that reservoir sections drilled with casing show enhanced productivity as much as twice the wells drilled conventionally. The Plastering Effect, as an inherent benefit of Casing Drilling, keeps the producing formation as intact as possible and reduces formation damage.

Most subterranean rocks contain natural fractures. Fluid loss severity in reservoir sections increases with increasing width of the fractures. Apart from the economics of lost drilling fluids, preventing formation damage in the reservoir section is of paramount importance. The application of non-damaging lost circulation material (LCM) has been the traditional solution to control losses in these scenarios. The performance of such LCM mixtures is usually determined with a Particle Plugging Apparatus (PPA), using aloxide discs for evaluating fluid loss. These discs more closely emulate a permeable sandstone, with varying pore throat sizes, than a natural fracture. The formation of an impermeable plug which can sustain higher wellbore pressure is desirable when treating a fracture, but in a producing formation the plug is removed by the produced fluid or by a remedial treatment. To better emulate both natural and induced fracture geometry, slotted discs of constant width were introduced; however these slots represent only the face of the fracture where LCM forms the bridge. The bridge may become eroded due to shear stress of the drilling fluid, leading to reestablishment of lost circulation. To remove these limitations, a new tapered slot was designed in which the fracture opening size varies from its face to its endpoint over a certain length, more closely resembling a fracture. Different combinations of ground marble (acid-soluble) were tested using the tapered slot. Many times it was observed that although the slot was completely filled with LCM, there was continued fluid loss. Considering this, components of high fluid loss pills for such application need to be redesigned. Cellulosic and polylactide (PLA) fibres (5-15% V/V of LCM) were used in combination with particulates resulting in significant improvement in fluid loss control. Other mechanical properties of particulate material were also studied and their importance in controlling lost circulation control established. This paper reviews the application of this testing equipment and methodology with non-damaging fibers for lost circulation control to minimize formation damage in reservoir sections.

In Ecuador, the principal reservoirs are subhydrostatic, with permeability ranging from 100 to 2,000 mD and significant clay content. The crude oils are prone to form emulsions in contact with completion fluids. After workover operations—pulling electric submersible pumps (ESP) or recompleting a well—it is common to lose more than 1,000 bbls of completion fluid, resulting in a 20% to 50% reduction in production. Fluid loss control pills containing sized particulate, such as calcium carbonate or sized salt, are frequently used to control the fluid loss; however, a further treatment is required to remove the solids. Using this technique, 25 wells producing a total of 8,000 BPD were worked over, after which the production decreased to 5,000 BPD. The main challenges in developing a solids-free fluid loss control pill to control losses of completion fluid during a well intervention are: a) the low, subhydrostatic (0.16 to 0.36 psi/ft.) reservoir pressure, b) high matrix permeability, and c) cleanup when well is put on production. To overcome this, a highly viscous, polymer crosslinked fluid with an internal breaker was developed to temporarily isolate the reservoirs. Using this fluid, it is possible to work over a well without losing fluid into the reservoirs and having the associated loss of production. In 15 wells worked over using the fluid loss control fluid combined with modified workover procedures, fluid losses were controlled and production was maintained after the workovers. This technique also made it possible to selectively stimulate certain intervals, increasing production. The total production prior to the interventions was 7,300 bpd. Afterward, it increased 27% to 9,250 bpd. The fluid-loss control fluid, together with the new workover procedures, has now been adopted as a standard. It has proved an effective means to protect the subhydrostatic reservoirs in mature fields during workover interventions.

Lost circulation in fractured formations is one of the drilling's biggest expenses in terms of non-productive time (NPT), unit mud cost and safety issues. The severity and persistence of losses are to a large extent determined by the type of formation into which the fluid is being lost. It is imperative to identify whether the losses are to natural or induced fractures as losses into naturally fractured rocks require different treatments than those into drilling induced fractures. One way of identifying the type of the fracture is by image logs which are very local and limited to conductive muds, so still in their infancy and have yet to gain wide acceptance. An alternative way is possible by looking into flow behavior of mud losses (flow in/out) and associated downhole pressure response (PWD data). This work presents an analytical formulation describing mud losses in drilling induced fractures based on which the volume and rate of losses in an induced fracture are quantified in terms of fluid properties, fracture parameters and operational conditions. Comparison between the predicted mud losses into induced and natural fractures indicates that much higher pressure sensitivity is anticipated during mud losses into induced fractures. Hence, the pressure sensitivity analysis can be used as a means to distinguish between the losses into natural and induced fractures. Once the fracture type is identified, the fracture parameters (hydraulic width or compliance) can be estimated by analyzing mud loss data. As the outcome of this study, guidelines are provided for the best practices to be used for prevention and control of lost circulation.

Displacing drilling mud with clear solids-free completion brine is one of the most critical steps during well completion. Drilling deeper below the mudline (25,000+ feet) and exploring deeper water depths requires critical evaluation of conventional displacement methods and testing procedures and leads to a more rigorous displacement scenario. Deep wells generally contain greater volumes of working fluid, larger diameter wellbores and drill strings, more feet of casing, and significantly increased surface area that require effective cleaning of mud residue and debris during the displacement process. Therefore, such wells typically require larger volumes of displacement spacers, enhanced pumping rates, and enhanced cleaning chemicals that tolerate substantial mud contamination while maintaining cleaning effectiveness. In order to properly design displacement spacer systems, these parameters must be incorporated into the evaluation and testing scenarios. This paper describes methods and processes that incorporate the key wellbore parameters, including temperature and density requirements, into the displacement spacer system in order to define the size of spacers, amount of cleaning chemical included in each spacer, number of spacers required, and test methods used to validate the displacement design for the target well. Case histories illustrate how to design and execute an efficient and effective displacement job and the cost savings involved when a displacement system is properly developed. Failure to complete properly the displacement process can lead to complications in subsequent completion and tool operations, and contribute to wellbore control issues. Furthermore, increased formation damage due to residual solids and time lost to resolve any issues can significantly increase the cost of the completion.

Solids-free completion brine is the ideal fluid to complete wells employing sophisticated downhole tools with limited metal-to-metal clearances, as well as those requiring sand control operations. Unfortunately, clear brines have no inherent control of fluid loss, leading to poor completion performance, increased formation damage and well control issues, all of which contribute to lost production time. More specifically, fluid engineers have reported greater formation damage due to increased brine-formation interaction while reporting losses as high as 100 barrels per hour. Critical evaluation of these factors coupled with the complexity and cost of today's projects, reinforces the need for chemical systems that immediately and effectively control fluid loss with minimal formation invasion. Cross-linked pills prepared at the rig site gained industry-wide acceptance by reducing fluid loss to just a few barrels per hour. However, deficiencies of rig-prepared pills occur, such as loss of incompletely cross-linked material into the formation, pre-mature cross-linking that inhibits delivery, significant time needed to make a quality pill, and associated HSE issues that limit the manufacturing of pills at the rig. As a result, researches developed second-generation solids-free FLC pills, which feature pre-cross-linked polymer. This second-generation system provides new dimensions in pill technology that further improve the efficiency and consistency of traditional rig-prepared FLC pills. This paper presents methodology for using this new class of pre-cross-linked solids-free FLC pills as well as data defining their properties and characteristics including significant reduction in rigsite HSE issues and superior quality control conducted at the manufacturing plant. This paper also presents field case histories demonstrating the use and effectiveness of optimized, fully pre-cross-linked FLC pills ready for immediate use at the rig.

Crude oil compatibility testing with completion brine is necessary to prevent the formation of crude oil-brine emulsions that cause formation damage and limit hydrocarbon production. Furthermore, required remedial action is costly. Conventional testing for the formation of oil-brine emulsions requires large volumes of oil, typically 50 to 75 mL oil for each test. Completion brine projects can require more than forty tests to identify adequately all fluid compatibility issues, which translates to about three liters of crude oil. However, high profile projects often deliver only limited quantities of crude oil, sometimes only 500 milliliters or less are available for emulsion testing. To accommodate the growing demand for oil volume, researchers developed a new high-shear method and apparatus that uses a total per test volume of 10 milliliters, including crude oil and brine, fracturing gels, fluid loss control gels, broken gels, filtrates or stimulation fluids, and combinations thereof. With this methodology, a series of 40 crude oil compatibility tests requires only 200 mL of crude oil. The apparatus is constructed from common laboratory equipment and readily available devices. Markedly, the equipment delivers consistent high-shear mixing, clear visualization of fluid interfaces, capacity to stack three or more test fluids in a single test, and the ability to heat age samples to about 82°C (180°F). Testing demonstrated that the new high-shear method and device produce reliable results using small volumes of crude oil and compare positively with conventional test methods. Since this method is applicable to all fluid-fluid testing, a proposal will be presented for inclusion into ISO-13503-3 (API RP-13J), Testing of heavy brines.

Abstract Drilling fractured formations by overbalanced method causes lost circulation of drilling fluid in fractures. The lost circulation in drilling fractured zones has been traditionally accepted due to inability to control its occurrence. Most of drilled wells in fractured oil zones after completion are conducted on acid job in order to obtain well flowing. If the radius of skin due to lost circulation of drilling fluid through fractured oil zones be determined, the volume of acid needed to conduct any acid job can be calculated. The main goal of this work is to obtain a mathematical model for determination of skin radius in naturally fractured oil reservoir wells. In this study, one vertical fracture is assumed to symmetrically intersect a wellbore. During a lost circulation drilling fluid enters the fracture and displaces formation fluid. The mechanism of lost circulation through the modeled porous medium is formulated using mass transfer phenomena. Obtained equations give concentration of the lost fluid with respect to time and position. Filtration of the drilling fluid at walls of the fracture is considered to be exponential which is ceased after mud cake is formed. A simulator is developed using derived equations in this work. The concentration of the drilling fluid could now be plotted against the position in the fracture and also against the position in lateral direction for each point in the fracture at a given time. These curves tend to be S-shaped. The position in the fracture at which the curve of concentration reaches zero could be considered to represent skin radius caused by drilling operation. Similarly the position in lateral direction at which the concentration reaches zero represents lateral penetration of the drilling fluid in the matrix from its corresponding position in the fracture. Introduction Drilling of a potentially productive formation can be expected to cause some skin damage. The seriousness of that damage depends upon the nature of the formation, the composition and properties of the drilling fluid, and the drilling conditions. Usually the drilling fluid pressure is greater than the formation pore pressure. As a result there may be invasion by whole drilling fluid and solids from the drilling fluid as well as invasion by drilling fluid filtrate. Most of the factors known to affect particle and filtrate invasion are not readily subject to control. For example, high differential pressure often must be tolerated. Scrapping action of bit and drill string cannot be eliminated. There are limits to adjustments that can be made in drilling fluid circulating rates. On the other hand, the filtration characteristics of the drilling fluid can be controlled to prevent invasion. Further protection against formation damage can be exercised by selecting a type of drilling fluid to limit or avoid undesirable interaction of filtrate with the formation. [1] During invasion, drilling fluid displaces formation fluid and causes a mixing zone with a resultant S-shaped concentration profile to develop. Dispersion phenomena may be attributed to several physical phenomena including molecular diffusion, velocity profile effect, series of mixing cells, stagnant pockets and variation in flow paths. All these phenomena except molecular diffusion are dependent on convection of fluids through a porous medium. [2] There are different methods so far provided in order to simulate dispersion in a fractured formation. These modeling approaches are divided into two main classes: continuum models and discrete fracture models. [3] Dispersion in fractured media is typically simulated using one or more of the following conceptual models: equivalent porous medium (EPM), dual porosity, discrete fracture network (DFN), or hybrid DFN/EPM approaches. [4]

Abstract A high percentage of oil and gas wells drilled throughout the world have been completed using perforated casing. In older cased-hole wells, the production pressure may be depleted and/or hydrocarbon flow may be impeded by various damaging mechanisms such as in-situ emulsions, water blockage, solids migration, asphaltenes and paraffin deposition. In newer wells, drilled using oil- or synthetic-based drilling fluids, emulsion blockage may cause near-wellbore damage when the filtrate or whole mud interacts with formation fluids or completion brine. Properties of microemulsions, such as high oil solubilization rates and ultra-low interfacial tension make this type of fluid ideal for addressing all of the described problems in old and new cased-hole wells. This paper presents development procedures and case history results from numerous field applications that demonstrate the efficiency to reduce skin damage and improve productivity by using a single-phase microemulsion fluid specially designed for cased-hole wells. Introduction In cased-hole wells, the production pressure may be depleted and/or hydrocarbon flow may be impeded by formation damage. In the majority of oil and gas wells completed by perforating casing, formation damage may include wettability changes, in-situ emulsions formation, and water blockage. 1–3 Operators have been using various remedial treatment methods for removing near-wellbore damage in cased-hole wells, including the injection of acids and solvents such as xylene, oils, or alcohols, in combination with surfactants. 4, 5 Although they may partially or completely restore the permeability of the porous media, many of these treatments are not completely effective, because they do not restore the wettability properties of the rock. Consequently the production of the oil and gas will not reach the expected production level. The type of wettability of the formation rock is important, because it controls flow and distribution of fluids in a reservoir.6 The original water-wet characteristics of most reservoirs are changed by the adsorption or deposition of organic molecules present in the crude oil. These organic molecules contain polar groups, generally consisting of oxygen, nitrogen, sulfur, in addition to hydrocarbon tails. These components are also known as natural surfactants. 6 The polar groups adsorb onto the rock, exposing the hydrocarbon tail and changing the surface to oil-wet. The wettability of formation rock can be also altered by surface-active additives used in drilling and completion fluids. 2 Another significant damage mechanism is the formation of in-situ viscous emulsions produced by incompatibility of fluids when the formation fluids, including crude oil or formation water, contact the drilling, completion or treatment fluids. 7 Phase trapping is one of the most severe damage mechanisms in low permeability gas reservoirs. This effect can occur in gas reservoirs with the presence of water- or hydrocarbon-based fluids. The porous media of a reservoir is initially at a low liquid saturation which provides the maximum cross sectional area for flow through the rock matrix, and therefore has the highest level of permeability. If a fluid, such as completion brine, is introduced into the porous system a higher water saturation in the flushed zone could be generated and would result in trapped gas. If the capillary drawdown gradient is insufficient to overcome the capillary pressure when the well starts production, a high pressure trapped liquid saturation results. 8 Waterblock is one of the foremost formation damage mechanisms that requires attention. Waterblock may result from the invasion of water-base fluid or flitrate into an oil-bearing formation which increases the near-wellbore water saturation. This effect is elevated with the retention and adsorption phenomena of polymeric additives which pass through the drilling fluid filter cake and invade deeply into the reservoir. 9, 10