In offshore drilling technology, spacers are used prior to the cementing job for wellbore cleaning and improving cement bonding. Spacers are also used for remedial purposes such as formation damage control or prevention of further formation damage. Lost circulation is one of the major issues encountered when dealing with a damaged formation and must be assessed immediately and ceased before further issues occur. This proprietary spacer contains a blend of coarse, granular, organic, biodegradable material and can seal up to 4 mm gaps. In this paper, we discuss an optimum spacer with a novel biopolymer and loss circulation material which are used successfully for cementing jobs under challenging loss circulation conditions. This study explains the performance of this optimum spacer. The optimum spacer has been successfully applied on offshore wells specifically for preventing and remediating lost circulation issues while cementing. The rheological properties of the spacer at both ambient and elevated temperature were analyzed and reported. The compatibility tests between the spacer and drilling fluid and cement slurry were also conducted along with the sealing properties of the spacer. The sealing properties were determined in a fluid loss cell with 20/40 frac sand, and were also tested through a particle plugging apparatus at various gap measurements. In this study, spacer compositions and densities were adjusted to examine effects on rheology and stability of the solids within the system at ambient and elevated temperature. Also, this novel spacer improved the compatibility with synthetic/diesel-based drilling fluid and cement with less or no viscosification compared to commercial spacers. In addition, the spacer shows to effectively seal 20/40 frac sand at 100 psi as well up to a 4 mm gap at 1000 psi. The first case history for this technology has been successfully completed and are presented and discussed in detail. The innovative spacer system is proven within this paper to add significant value to extreme cementing operations by improving and maintaining impressive sealing capabilities and can reduce formation breakdown and fallback of cement tops. The spacer comes along with advantages that include compatibility with various drilling fluids and cement. This spacer is environmentally friendly and applicable in both vertical and horizontal wells. In addition, the spacer will form a seal to minimize filtrate invasion into the formation, effectively reduce loss circulation and enhance hole-cleaning prior to cement placement.

The design of lost circulation remediation strategies is complicated in naturally fractured reservoirs. It has been a great challenge for engineers to balance between fracture plugging and formation damage. In this study, experimental investigations and statistical analysis were conducted to explore the effects of LCM implementation strategies in lost circulation remediation and formation damage control. Different combinations of granular and fibrous LCMs were tested in a permeability plugging apparatus with slotted discs. When LCM particles accumulated at the slots and formed a low-pressure-bearing plug, the injecting pressure was held constant to enable further establishment of the plug through filtration. The effects of LCM soaking time, soaking pressure, and injection rate on plug breaking pressure and total fluid loss volume were investigated. Full factorial experimental design and analysis of variance (ANOVA) were performed to study the statistical significance of each parameter. For granular LCM mixtures, the soaking pressure and time did not have a significant impact on the ultimate plug breaking pressure and the cumulative fluid loss. For mixtures blended with fibrous LCMs, longer soaking time contributed to increasing the plug breaking pressure and reducing fluid loss. A low LCM pill injection rate reduced the fluid loss volume comparing to a high injection rate upon the establishment of an effective seal. Incorporating fibrous LCMs enhanced the slot sealing effects since the dehydrated mud plug formed not only at the fracture mouth, but also inside the fracture. This prevented the plug from being washed down when drilling resumes. The results and conclusions from this study provide new insights on the identification of optimal LCM implementation strategy with better formation damage control.

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.

Controlling lost circulation during drilling operations in a reservoir prone to losses is typically remedied by cement squeezing or plug setting. The aim being to minimize or stop drilling fluid losses and to regain full returns at surface, and to affect wellbore integrity. Different placement methods of cement plugs have been discussed in detail in the literature, except for the ‘level-off’ method, which is particularly effective for curing complete loss circulation cases. Following the mathematical modeling of this cement plug placement method, its design, procedure and execution are discussed, together with some successful field cases, both drilling and workover situations in highly-fractured carbonate reservoirs in the Middle East. Using drill pipe and an installed a Retrievable-Test-Treat-Squeeze (RTTS) packer, with some spacing from the loss zone, the method entails that the cement slurry is allowed to drop by gravity in order to cure lost circulation. As the column of fluid, mud and slurry in the well exceeds formation pore pressure, i.e. overbalanced conditions, a volume of acid-soluble cement slurry is allowed to slowly drop and freely penetrate the formation, i.e. through its fractures or caverns. During the penetration of this viscous slurry into the loss zone, the cement can set and the fracture or fissure openings are plugged. In addition, to minimize or prevent further losses, this cementing technique may also mitigate formation damage of adjacent zones. Presented are detailed design calculations for the level-off placement technique: determination of required cement slurry and displacement volumes, and recommended displacement and RTTS packer setting depths. The expected depth of the top of cement is estimated. The design parameters are compared with field cases and explanations are given for possible discrepancies. Detailed field procedures and execution are also presented. This is the first known, detailed description and modelling of the level-off cement placement technique in the literature.

Whilst drilling the 12 ½" and 8 ½" sections on a HPHT field in the North Sea, fluid losses were encountered which required the pumping of high concentration Loss Circulation Material (LCM) as well as multiple ‘through the bit’ cement squeezes. The reservoir had been under production for many years and was now at a point where it had significantly depleted and the formation was very delicate, making it easily subjected to fracturing. Losses were expected to be an upcoming challenge as the mud weight window was so narrow and due to the HPHT rating of the offshore reservoir and the fractured nature of the geology, this posed as a serious risk that required pre-planned mitigation. The ability to pump ultra-high LCM concentrations was discussed in pre-planning as being one of the key mitigation strategies to stemming losses. However, it was thought that pumping LCM would block a typical MWD pulser due to the narrow geometries of the flow paths within. Successful onshore testing was conducted prior to drilling operations to prove that the MWD pulser selected had the ability to permit the flow of ultra-high concentrations of LCM. A closed loop system was created onshore and LCM with concentrations up to 420kg/m 3 (147lbs/bbl) was pumped through the MWD tool without blocking it up and with full functionality throughout. This gave the operator the confidence to pump LCM through the MWD tools, if required in the field. The use of an MPD (Managed Pressure Drilling) system was also required to keep the equivalent circulating density within the tight mud weight window by maintaining a constant bottom-hole pressure through the application of Surface Back-Pressure (SBP). This was critical as the well, when static, was underbalanced. The incorporation of MPD also gave the operator the ability to ‘squeeze’ LCM/cement into the well and formation by applying surface back pressure during ‘through the bit’ LCM/cement jobs. During field operations, the operator did go on to pump a 320 kg/m 3 (112 lbs/bbl) LCM pill through the MWD tool without plugging during a loss scenario. Pumping LCM through the MWD tool reinforced the formation and enlarged the mud weight window from <0.01sg to 0.03sg allowing operations to continue. In addition, muliple "through the bit" MPD LCM/cement squeezes were conducted on two wells in the same field with no negative effect on any of the MWD tools. The partnership between the MWD and MPD systems formed a key part of the losses management. The MWD system could identify exactly what downhole pressure losses were seen at, which was then transmitted by the pulser to the surface. The MPD system would then use an algorithm based calculation to apply the exact required SBP to maintain a constant bottomhole pressure, that was within the mud window. This provided the operator a safe and efficient solution to continue to the target depth in a very challenging narrow margin well.

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.

Polyelectrolyte complex nanoparticle (PECNP) systems compatible with produced water were developed to improve supercritical CO 2 (scCO 2 ) foam stability and to reduce fluid loss for fracturing applications. Foam viscosity, stability, fluid loss properties and cleanup of injected liquid through the formation were enhanced by PECNP-surfactant systems prepared in produced water medium. Taking advantage of produced water as energized fluids for fracturing requires enhanced compatibility of gas/liquid mixture. Two produced water recipes of 33,333 and 66,666ppm TDS were used to prepare 1 w/w% surfactant solutions. PECNP was formed as a mixture of positively- and negatively- charged polyelectrolytes. Experimental setup was designed to determine the aqueous foam stability at actual reservoir conditions. Rheological measurement was performed to measure the stability of the bulk foam under shear and to evaluate the foam texture properties. The improved viscosity of different proportions of PECNP-Surfactant (9:1, 8:2, 7:3, and 6:4) in aqueous foam mixtures was observed as compared to surfactant stabilized CO 2 foam. The flow consistency index observed in the shear thinning region was also increased from 1184.3 to 2916.4 Pa s n in 33,333ppm and from 1035.7 to 1683.1 Pa s n in 66,666ppm brine solutions. The view cell results revealed the high stability and longevity of scCO 2 foam employing various proportions of surfactant to nanoparticle as oppose to surfactant generated foam in which the foam height shortened faster. The presented scCO 2 generated foam can preserve the foam cellular structure in absence of crude oil. The PECNP-Surfactant system successfully lowered the interfacial tension to up to 74% and 93% for 33,333 and 66,666ppm brine salinity, respectively. Fluid loss was measured to evaluate fluid leak-off from a core when the high flow velocity along the core exists. The fluid loss for both CO 2 and water leak-off were also lowered employing PECNP- Surfactant containing foam.

Lost circulation is commonly recognized as one of major drilling complications that cause low efficiency and a high cost in oil or gas well drilling. The current practice of mitigating lost circulation with lost circulation materials (LCM) is still empirical due to the lack of understanding of near-wellbore conditions. This work the first time uses pressure transient data analysis method to infer the near-wellbore conditions in lost circulation wells. The fluid level survey data can be converted to bottomhole pressure p data based on mud weight. Plot of numerical pressure derivatives data versus time data allows for identification of near-wellbore conditions and thus selection of the right type of LCM. Result of this study shows that a zero-slope trend in the plot of numerical d p d t data versus time t indicates a near wellbore condition of intersecting radial multiple fractures induced by heavy drilling fluids. Medium size LCM with a wide range of particle size distribution in a lighter drilling fluid are recommended for curring the well. A zero-slope trend in the plot of numerical t d p d t data versus time t indicates a wellbore that does not intersect any fracture. This suggests using fine size LCM with a narrow range of particle distribution in a lighter drilling fluid to cure the well. A zero-slope trend in the plot of numerical d p d t 1 / 2 data versus time t implies a wellbore intersecting a singal fracture. This usually occurs in drilling naturally fractured carbonate reservoirs. Coarse size LCM with a wide range of particle size distribution are recommended for curring the well. A field case study illustrates that the result given by this investigation can be used for selecting LCM on the drilling site.

Deposition of scale is one of the most common and serious problems seen in HPHT gas wells in Saudi Arabia. A Coiled Tubing intervention to mechanically clean out the scale deposits from the production tubing and liner has been the most common approach to address the problem. Since reservoirs get depleted with time, lost circulation becomes a severe issue. In wells that cannot support a column of fluid due to low reservoir pressure, the reservoir (open-hole, perforations) needs to be isolated to regain full circulation that allows to lift the milled scale to surface. A conventional procedure to isolate the reservoir is to use Calcium Carbonate chips until leakoff into the formation is controlled. This approach is successful in isolating, but presents significant disadvantages regarding the amount of chips needed to successfully isolate, and, more importantly, the cleanout of this solid material once the de-scaling operation has been concluded. This paper discusses the first successful reservoir isolation using exclusively a temporary gel plug that allowed safe and successful execution of a mechanical de-scaling operation without using CaCO3 chips. Temporary gel plugs are normally polymers dispersed in water that can be either crosslinked or non-crosslinked. Well variables like well configuration, bottom-hole temperature; desired plug stability as well as operational variables such as pump rates and placement times are used in selection and design of the type of plug to be used. In the specific case of the reservoir isolation needed to perform a de-scaling operation, a delayed crosslinked polymer gel plug that generates over time a firm and highly viscous gel was used. This temporary gel plug was placed by bullheading two batches of this system down to the top of the openhole wellbore section and allowing an 8 hours setting time to crosslink and isolate the low pressure zone where fluid will leakoff thus generating a lost circulation. The reservoir isolation was confirmed by positive pressure testing the plug. The specific temporary gel plug was designed to be readily soluble in acid in order to restore communication with the reservoir and resume gas production without a need for any additional cleanout runs with Coiled Tubing and use of large fluid volumes.

An improved 1D-averaged model for wormhole propagation was developed that considers acid spending and leakoff along wormholes. The 1D-averaged type of model is one of several types that have been developed for predicting wormhole propagation during matrix acidizing treatment in carbonates; other models include discrete models, Darcy-scale 2D and 3D continuum models, and multi-pore-scale network models. Among these models, the 1D-averaged model is commonly applied in acidizing simulation software because of its simplicity. Most of 1D-averaged models are based on the pore volume to breakthrough correlations developed from core flooding experiments on different rock samples and acid systems. It is also generally assumed that the effect of acid spending is already included in the experimental results. Although this is a reasonable assumption when the wormhole length is shorter than the core length (typically 6 in.), once wormhole penetration is longer than 6 in., the acid spending becomes more significant while acid travels along wormholes due to the reaction between acid and the side walls of wormholes. Meanwhile, acid leak-off through wormhole walls becomes an important factor for longer wormholes. Not considering acid spending and leakoff in relatively longer wormholes may result in overestimation of wormhole penetration depth. In our model, we adopted an empirical correlation to determine the leak-off velocity profile along wormholes. Then, we developed a numerical model to simulate the non-uniform acid concentration along wormholes. Both the empirical correlation for leak-off velocity profile and the numerical model for acid concentration are validated by comparing to published materials and an independent computational fluid dynamics (CFD) software. As expected, wormhole penetration predicted by the new model shows shorter wormholes than the traditional 1D-averaged model. We applied the new model to a field case and showed its capability of reasonably matching the downhole pressure during acidizing treatments and PLT data before and after acidizing treatments, which demonstrates the applicability of the model to job design and interpretation in the field.

Recent studies have offered evidence of unique shear viscosity loss of borate crosslinked fracturing fluids when exposed to hydrostatic pressures, such as those encountered during deep water hydraulic fracturing. This phenomenon can have important implications for proppant transport and for the resulting fracture geometry that needs to be accounted for in fracture design. Another important aspect for fracture design is the fluid loss. Since crosslinked fluids have superior fluid loss characteristics compared to linear polymers, the question arises as to whether fluid loss of borate-crosslinked formulations is also affected by pressure. Fluid loss is a fundamental property in hydraulic fracturing treatments and may dictate the attainable fracture geometry and the retained conductivity. Prior knowledge of fluid loss is also important for designing special additives to overcome the effect of excessive fluid loss. This experimental study was designed to determine the pressure effect on linear guar and both borate and zirconium-crosslinked polymers. The concept of melt point utilized for the viscosity dependence was incorporated to select fluids. A unique high pressure, high temperature fluid loss apparatus was developed for the experimental testing. Test parameters varied from 160 to 260°F, 1000 to 9000 psi and 0.1 to 10 mD sandstone cores. Spurt and fluid loss coefficients were determined and compared to determine the pressure effect. The results indicate that fluid loss behavior of fluids comprising borate-crosslinked guar is susceptible to moderate pressure effects. In particular, spurt losses increased with pressure, whereas fluid loss coefficients were independent of pressure. The increase in spurt loss with pressure was more pronounced as the permeability of the core sample increased. Conversely, the fluid loss behavior for linear guar or derivatized guar crosslinked with zirconium was not influenced by pressure. The implications of these findings for hydraulic fracturing applications are also discussed.

Fluid-loss is significant for the standard fracturing-fluids without adding solid materials. One method to reduce fluid-loss is to add silica flour, although it reduces fracture conductivity. Other methods are to use wall building polymers. However, the fluid-loss is still significant and complete removal of wall building materials are not possible even with breakers. We found that powder, granular and fibrous materials made of Polyglycolic Acid (PGA) or Polylactic Acid (PLA) are very suitable for fluid-loss agents since they are as strong as rock, while they dissolve as liquid acids after applications. Fluid-loss tests are conducted using the standard API slot tester and filtrate loss tester, mixing powders, grains and fiber, all made of PGA or PLA in frac polymer fluids. Ratio of grains, powder and fiber is optimized to minimize fluid-loss for porous media and fractured porous media. Then, the changes of particle size are measured under heated conditions. Fracture simulation studies are also conducted using a 3D fracture boundary element model to compare the fluid efficiency of the fracturing fluids with and without the PLA and PGA particles. The results show that the capability of preventing fluid-loss and plugging micro-cracks is maintained for the porous filters and small slots within reasonable time period. For short term applications less than 3 hours, both PGA and PLA fluid-loss agents are stable when the temperature is less than 212 °F. Mixing these materials often provides more efficient properties to reduce fluid-loss and to bridge micro-cracks. No residues are left after experiments if the fracturing fluid is kept being heated for 24 hours. The amount of the PGA and PLA fluid-loss agents required to reduce the fluid-loss is not significant. Hence, their field applications are feasible judging the cost and the benefit. The advantage in using these materials is that they turn from solid to liquid after applications so that no formation damage and no proppants conductivity damage occurs. The fluid-loss is also significantly reduced with the powder particles. In addition, because the PGA and PLA materials are degradable, solids with arbitrary sizes and shapes may be used as long as they control fluid-loss and plug fine fractures. Their applications are not only limited to reducing fluid-loss but they may be used for engineering fracture design to enhance the fracture conductivity.

Lost circulation has plagued the industry since the beginning of drilling. Historically, severity of losses has been categorized based on the amount of barrels lost to the formation, i.e., seepage, partial, and total. Though helpful, this strategy doesn't help understand the underlying drive mechanism(s) for losses and doesn't provide enough data to propose a solution. The recently adopted category is focused on the lost-circulation mechanism based on the properties of the exposed formation; these classifications are losses to 1) pore throats, 2) induced or natural fractures, and 3) vugs or caverns. This study provides an integrated workflow to predict expected losses for such classification/mechanism of losses. Mud loss through fracturing is categorized based on fracture types, i.e., natural or induced fractures. Different models are used with respect to the fluid-loss mechanism in natural and induced fractures. These models take into account the effect of fracture breathing. In addition, mud loss through the pores on the wellbore and the fracture face is modeled based on formation and mud-cake filtration properties, coupled with the fracture losses. Losses through induced fractures generally occur when ECD exceeds fracture gradient. This happens due to erroneous prediction of the mud weight window, lack of the key information, harsh downhole pressure/temperature and some other operational factors. A field case from deep water Gulf of Mexico is presented in this paper showing how an inaccurate mud window can yield in drastic mud losses. In addition, rock properties and field in-situ stress govern fracture width and fracture propagation. Losses to vugs/caverns are usually total losses due to very large openings in the rock; recommendations are provided on how to control severe losses. Lost circulation not only causes the adverse effect of mud loss itself; it can also lead to several other issues, such as formation damage, stuck pipe, hole collapse, and well-control incidents. The current industry trend is moving towards drilling more low-pressure zones, and lost-circulation planning is becoming a vital part of these projects. Knowledge of the type and the expected amount of mud loss can help engineers select the most appropriate and effective solution and preplan accordingly. This information also provides criteria to evaluate the effectiveness of the applied lost-circulation strategy. In this study we review LCM treatments, wellbore strengthening, MPD, and CwD as some of the most common remedial techniques.

The drilling industry routinely encounters formations with pore pressures that are lower than anticipated. In some cases, these pore pressures require specialized treatments to control the loss of whole drilling fluid. A massive loss of whole drilling fluids, whether water-based or oil-based, can be costly, result in nonproductive time (NPT), and if encountered near potential productive zones, also result in damage to the producing capability once completion has been performed. Key wellbore data, such as actual hole size versus drilled hole size, accurate bottomhole circulating temperature (BHCT), and placement technique with optimum bottomhole assembly (BHA) for accurate placement of treatment design is critical for job success. Placing a successful treatment for the control of whole mud losses and to minimize possible formation damage can be a complex and often expensive undertaking. Numerous solutions have been identified in the industry ranging from effective bridging or lost circulation material (LCM) incorporated in the mud to complete process solutions such as crosslinked fluid structures to ultimate cement slurries. The damage that is left as a result of the fluids pumped is a major disadvantage of most systems. This paper presents a novel approach using a rigid setting fluid (RSF) that can be engineered to maintain a low viscosity during placement and activate by temperature to transition from a fluid to a set state almost immediately to effectively control further losses to the formation. In addition, using the right angle set (RAS) created by the exothermic reaction, the system can tolerate contamination of extraneous fluids up to 50% and still provide adequate compressive strength. Lastly, the material is soluble in acid with a predicted 99% regained permeability. A case history will be presented where the RSF treatment was used and effectively controlled, eliminating further whole mud losses to the weak formation.

Micellar fluids with viscoelastic behavior, or viscoelastic surfactant fluids, are used in the oil industry as completion and stimulation fluids. The viscoelastic (i.e. viscous and elastic) behavior of these fluids is based on the overlap and entanglement of very long worm-like-micelles. High fluid leak-off has, however, limited their application for hydraulic fracturing and frac-packing applications. Recent developments have found that micellar fluids can have wall-building leak-off control similar to crosslinked-polymer fluids (CPF) by the addition of a small amount of inorganic crystals that are less than 100 nanometers in size (i.e. nanoparticle). This paper will investigate the mechanism of fluid loss control for the particle-micellar fluid system. The tiny particles have high surface force, including van der Waals and electrostatic forces. The nanoparticle surface forces pseudo-crosslink the elongated micelles, which is similar to crosslinking polymers. The unique pseudo-crosslinking of surfactant micelles and particles has demonstrated improved viscosity, the formation of a filter cake, and enhanced thermal stability. Laboratory tests show the development of a filter cake significantly reduces the rate of fluid loss and demonstrates wall-building rather than viscosity-dependant leak-off control. Two models of static fluid loss control for particle-polymer fluid system will be reviewed. Fluid leakoff characteristics will be compared between the particle-micellar fluid system and particle-polymer fluid system. Uniqueness of this system is that the fluid loss control was achieved without compromising the internal breaking efficacy. Ordinarily additives 'plasticize' the micellar or colloidal aggregates. However, through our patented processes, we were able to successfully place the internal breakers inside the elongated micelles so as to not interfere with particles' pseudo-crosslinking. When internal breakers are activated by temperature, the elongated micelle structure collapses thereby significantly reducing the fluid viscosity and thus breaking down the filter cake into tiny particles. This results in clean breaking gel with reduced damage to formation permeability and fracture conductivity.

Abstract The literature describes several applications where Aphron fluid technology has been applied in both drilling and re-entry scenarios and includes an extensive description of how this fluid system works. A highly efficient leak-off prevention mechanism makes aphron based fluid systems beneficial for certain completion and workover applications as well, where formation damage could be avoided by the practical elimination of fluid-fluid or fluid-rock interaction or where simply the workover objectives can be achieved by obtaining efficient circulation of fluid to surface. Completion and workover applications for this fluid system have not been extensively reported. This paper reviews three applications of Aphron fluid technology in different completion and workover scenarios. The selected cases were reviewed to present some of the technical and operational lessons learned and to some extent discuss the observed formation cleanup behavior. The following three applications were reviewed: completion of a dual string sour gas well, using an oil based aphron system for kill fluid, with practically no kill fluid loss to a hydraulically fractured formation; the completion of additional zones within a depleted dolomitic limestone formation on two wells where the method of Aphron fluid placement was found to significantly affect fluid losses; and finally, the enabling of the provision of annular pressure support at pressures which approached the hydraulic fracture opening pressure of a shallow zone while hydraulically fracturing a deeper zone through tubing with a packer. Introduction The mechanisms by which the Aphron fluid system operates make it a reliable tool for certain completion and workover applications. These mechanisms have been described extensively in the literature (Brookey 1998; Ivan et al 2001; Growcock et al. 2005a; Catalin et al. 2002; Hoff, O'Connor and Growcock 2005). Moreover, the presentation of field performance data for Aphron fluids in drilling and re-entry operations is also extensively published (Ivan et al. 2001; White et al. 2003; Brookey et al. 2003; Rea et al. 2003 and Kinchen et al. 2001). Lessons learned from the performance of Aphron fluids in a wide range of applications have caused a specific profile to evolve for the effective use of this fluid technology. Brookey (1998) showed that the high low shear rate viscosity (HLSRV) of the Aphron fluid system, which provides the proper environment for aphron bubble formation and survival, also provides a high resistance to flow under low shear conditions, which significantly inhibits initial fluid loss to the formation. Brookey (1998), supported by Ramirez et al. (2002) showed that the creation of aphron aggregates is an effective filtrate control mechanism which further reduces fluid loss. Formation damage prevention is attributed to the inert gas which makes up the majority of an aphron aggregate, combined with the limited amount of fluid invasion into a potential leakoff zone. Adverse fluid-fluid and fluid-rock reactions are prevented because the completion and workover fluid is not available as a reactant or contaminant.

Abstract Identifying suitable kill fluids to temporarily control prolific oil and gas reservoirs without risk of formation damage has been a challenge within the Niger Delta. Various attempts, particularly in gas wells using conventional brines and gels to enhance well intervention processes normally require stimulation treatments, in order to bring the wells back to production. The engineered cross-linked gel is a temporary blocking formulation used to protect permeable zones from invasion of fluids. This system contains a low-residue cellulose-polymer with a cross-linking agent and can be designed for use with an internal or external breaker. In general, the use of loss circulation material (LCM) is not recommended because of its tendency to block perforations, complicate fishing operations and increase the difficulty of clean-up if fishing becomes unsuccessful. This case study is of a gas well drilled and completed for an Operator on the E4.2-reservoir with production capability estimated at 8,000 bbl/day of condensate and 150 mmscf/day of gas. Following the installation of the memory gauges, a 10-hour build-up test of this particular interval was conducted. During the retrieval of the BHP gauges, several incidents lead to three successive fishes getting stucked into the wellbore. The Operator was faced with many challenges: ‘do nothing and produce the well in an unsafe manner at 50% potential’, ‘attempt a workover’ or ‘attempt a coiled tubing rigless intervention’, with each option having its attendant limitations. The success in retrieving the multiple fishes was attributed to the ability to kill the high pressure gas well with a time dependent and acid degradable cross-linked gel system through a high rate bullhead pumping technique. The gel had low damage potential to the formation and prevented the migration and fingering of formation gas to the surface throughout the fishing operation that lasted for approximately one month on 24-hour daily operations. The pre-fishing conduit potential was preserved, indicating that the cross-linked gel completely got degraded internally at the end of the fishing operation leaving the near wellbore region undamaged. In this paper, the laboratory simulation, features, engineering design, field application and benefits of the engineered cross-linked gel system are discussed. In addition, the process of well killing, specialized coiled tubing and wireline fishing tools and performance evaluation are addressed. The success of the operation includes regain of the original well performance, competence in well killing and complex fishing, cost savings and high NPV. Over $2.0 million was saved operationally with the CT rigless activity when compared to ‘workover’ or ‘do nothing’ options. Background / Problem Statement The case study was the first of 16 drainage points planned to be drilled and completed for the supply of gas to the NLNG project from 1999. The well was drilled & completed on the E4.2 reservoir with a single 7″ × 5-½″ 13 chrome tubular completion. Following successful installation of the memory gauges and production well test, the well was closed in for a 10-hour build up. During retrieval of the BHP gauges the 0.125″ wireline broke at surface and fell back down the well. Attempts were made to cut the 0.125" wireline in the hole by using a blind box run on a second 0.108" wireline and toolstring. However, during the jarring process, the toolstring on the 0.108" wireline got entangled around the 0.125" wire in the hole and became stuck around the original fish at a depth of 11,762 ft. A centralised Go-Devil, followed by a cutting bar was dropped in an effort to recover the 0.108″ wireline, but the 0.108" wire was cut prematurely at around 627 ft, leaving both the memory guages, 0.125" and 0.108" wires in the well. A wire finder tool was run and confirmed that the Tr-ScSSSV was clear of wire, as the top of the wire was located at 586 ft.

Abstract In general, laboratory leak-off tests, either static or dynamic, are used to estimate the spurt loss. Most of the spurt loss values reported in the literature are measurements which result from the injection of brine based gels in brine-saturated cores. When using brine-saturated cores, an important aspect, which is the relative permeability to hydrocarbons, is neglected. The presence of hydrocarbons and the relative permeability to hydrocarbon and brine can significantly affect spurt loss. This paper discusses the impact of hydrocarbons on spurt loss in high permeability formations. Results of static and dynamic leak-off tests of frac/pack fluids in the presence of mobile oil saturation are presented. The main observation is that the spurt loss in hydrocarbon-saturated cores is significantly smaller than that observed in brine saturated cores. Another observation is that spurt loss decreases with increase of the hydrocarbon viscosity. Introduction In the context of this paper spurt loss is defined as an instantaneous fluid loss (Figure 1) into the formation during fluid invasion. It is generally assumed that during frac/pack treatments a large volume of spurt loss ocurrs 1–5 . Fluid efficiency and slurry schedule are highly dependent on spurt loss. Therefore, to achieve the desired fracture geometry and propped width it's critical to have the correct spurt loss value. A series of papers have been published reporting sizeable values of spurt loss for high permeability formations. The experiments in these papers were based on 100% brine saturated cores. However, the reservoirs in which the frac/packing operations are conducted have significant percentage of mobile hydrocarbon saturation. The presence of mobile hydrocarbon saturation can have a significant effect on spurt loss. The objective of this paper is to characterize the leakoff behavior of frac/pack fluids in the presence of mobile hydrocarbon saturation. In order to accomplish this objective, static and dynamic leakoff experiments were conducted using mobile oil saturated core samples. These tests were later compared to 100% brine saturated core samples. In addition, modeling was conducted to illustrate the importance and sensitive of spurt loss on fracture geometry prediction and tip screenout achievement. Experimental Description and Procedures Two types of tests - dynamic and static - were conducted. Dynamic Tests. The schematic of the experimental set up is shown in Figure 2. Gadiyar 6 gives detail description of the testing apparatus. Hassler type, multiple pressure port dynamic fluid loss core holder was used in all the experiments. Berea sandstone core samples with 2 in. diameter and 10 in. length were used. With a few exceptions, the permeability of the samples was 50 md. Static Tests. A high temperature and pressure (HTHP) fluid loss cell was used to conduct these tests. The specimens tested consisted of 2 in. by 0.25 in. berea sandstone disks with permeabilities varying from 60 md to 100 md. Dynamic Test Procedure. The experiments were conducted at room temperature. The confining pressure applied to the samples was 1500 psi. Initial brine permeability was measured by injecting brine at constant flow rate until the pressure drop stabilized. Then, the in-situ brine was displaced with mineral or crude oil at a constant flow rate until the brine saturation reached residual brine saturation. In the case of oil-saturated samples, at least two pore volumes of oil were injected to ensure achieving immobile brine saturation. The fracturing fluid (linear or crosslinked gel) was injected across the core face at a shear rate of 55 sec –1 . A constant pressure drop of 500 psi was maintained across the length of the sample. The cumulative leakoff volume was measured as function of time.

Abstract The analysis of mini fracs in high-permeability formations has been the subject of several studies and debates. In many cases, the leak off from the frac-pack appears to be less than that from the mini frac, which is normally conducted before the frac-pack. Consequently, the net pressure rise observed is less than the predicted net pressure based on the mini frac analysis. Rules of thumb have been developed to account for this apparent change in leak off behaviour. These rules include adjusting the spurt loss, choosing a latter-time closure pressure based on previous experience, and adjusting the observed fluid efficiency by an arbitrary factor. This paper attempts to provide a rationale for explaining the discrepancy between leak off data collected from mini frac analysis and the observed frac-pack behaviour. This paper also presents the results of laboratory experiments and field tests that show that the injection of a mini frac alters the observed fluid efficiency. Laboratory tests evaluated the magnitude and character of the fluid loss from subsequent injections of a frac-pack fluid. These tests were conducted with cores ranging from 100- to 3000-md permeability. Field results from trials in which two mini fracs were injected in the same zone are also presented. These field data are from wells in the Gulf of Mexico (GOM) and from a well in North Africa, all of which experience high fluid-leak off rates. The results from these injections show that the effects of mini frac fluid can alter fluid efficiency significantly. Finally, the paper proposes methods and best practices for measuring or counteracting this effect by altering the sequence of injections into the formation. Laboratory data supports the philosophy behind these best practices. In addition, field data illustrate the success of this altered injection schedule. Introduction When engineers design conventional low-permeability fracturing appliCat ions, they often assume that the fluid loss is dominated by filter-cake creation on the fracture face and no significant fluid loss (i.e. no spurt loss) occurs before the filter cake is formed. In high-permeability and/or depleted reservoirs, however, early leak off occurring before the development of a filter cake can dominate the total fluid loss. 1 The difference in fluid-loss behaviour for differing permeabilities is shown in Fig. 1. As permeability increases, the amount of spurt loss increases significantly and can dominate the total leak off. If job designers fail to account for the effects of early leak off both in the treatment design and the analysis of prejob injection tests, field treatment designs may be less than optimal. 2 Even though this understanding has improved the design process of high-leak off wells, suboptimal treatments suggest that other phenomena can affect our ability to accurately predict the onset of tip screen outs. The main factor that can interfere with optimum treatment design is the alteration of the leak off characteristics when a filter cake is created during the mini frac test. This filter cake, even with gel breakers, tends to affect leak off of subsequent pump-ins. This effect has not been previously investigated. This paper will evaluate laboratory and field data that contain multiple leak off periods. These data indicate that the filter-cake effect is permeability and time dependent, and can be removed by additional fluid injections. The laboratory and field data were used to evaluate these dependencies.

Abstract Coiled tubing services are frequently used to conduct kill operations concentric to existing production tubulars. These kill operations are typically performed to temporarily effect a hydrostatic balance of formation pressure at the exposed completion. Because coiled tubing well control operations are conducted concentric to existing production tubulars, special attention to job design and implementation is critical to ensure proper placement of kill fluids within the wellbore to achieve the desired pressure balance and to minimize the potential of formation damage. In those cases where wellbore operations subsequent to the kill program are not intended to return the existing completion to active status, formation damage induced by the kill practice is typically of little consequence. However, where return of the existing completion to active status is desired, the well control operation must be conducted with a complete understanding of the pressure balance and effect of kill fluid circulation on the completion. Many practices used in performing concentric tubing well control services lead to varying degrees of formation damage and impair completion flow performance. This paper discusses typical damage mechanisms resulting from completed wellbore kill programs, along with the related formation damage consequences for these types of operations, alternative well control kill processes using coiled tubing and the potential for reducing formation damage by using coiled tubing well control processes. In addition, recommendations for planning and implementing coiled-tubing conveyed well control programs within existing production tubulars are provided to guide the user in conducting well control operations with minimal induced formation damage. Introduction During the life cycle of a conventional completion, operations within the wellbore may be necessary which require the formation pressure to be hydrostatically balanced to achieve zero surface well pressure. For these types of operations, well control practices described as "kill programs" are employed to replace the existing wellbore fluids with a column of liquid having a density sufficient to create a hydrostatic balance with the formation pressure. This well control operation can be performed in several ways, using various fluid rheology types and densities, depending upon the operation to be conducted subsequent to the kill program. In general, conventional well completions are constructed with concentric tubulars assembled to achieve a desired function within the wellbore. During installation of the completion, the tubing provides a flow path for the circulation of pumped fluids from surface. However, once the completion tubing is pressure-isolated down hole using packers or other flow control devices, the circulation pathway to the completion may not be available depending upon the confines of the tubing design. If circulation of the wellbore fluids is not possible, a well kill pumping technique described as "bullheading" may be used. This well control operation is performed by pumping the kill-weight density liquids through the surface wellhead at a rate sufficient to displace the fluids from the wellbore tubulars back into the open completion. Bullheading operations offer minimal control of fluids placement within the wellbore and have a high potential for inducing extraneous formation damage. If the operations to be conducted subsequent to the well control program do not require continued service from the completion interval, then formation damage mitigation is not a major concern and the bullhead kill method is a viable option. However, where the well control operation is intended as a temporary pressure balance condition, the design of the well-kill program should focus on performing the kill with a minimum of induced formation damage. In this situation, concentric tube well intervention services have been successfully used to establish the fluids circulation flow path from the surface to the completion. Using this type of service, the kill operation can be performed by circulating out the existing wellbore fluids and replacing the wellbore volume with a kill-weight liquid having the desired rheology and density for the prescribed service.