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Rheological properties play key roles in hydraulic calculations and hole cleaning. Determination of the rheological properties in real time is very important to control the drilling operation and save time. Losing the rheological properties can lead to severe problems such as; pipe sticking, kick and blowout, increase in torque and drag, and hole cleaning issue. Rheological properties can be determine using the rheometer, which required time for measurement and also for cleaning the equipment after use. In the well site, rheological properties are measured twice a day. The objective of this paper is to develop a new technique to determine the rheological properties (plastic viscosity (PV), apparent viscosity (AV), yield point (YP), and flow behavior index (n)) of KCl water-based drilling fluid using the frequent measurements of the caliper parameters (drilling fluid density (D), Marsh funnel viscosity (MFV) and solid percent). D, MFV, and SV are measured frequently every 15-20 minutes in the well site. Artificial neural network (ANN) was used to build different models for PV, YP, AV, and n based on 3000 field data measurements. ANN was able to predict the rheological properties on a real time with a high accuracy. Four new empirical correlations were developed to predict PV, AV, YP, and n. The accuracy of these correlations are very high (correlation coefficient (CC) greater than 90% and the average absolute percentage error (AAPE) was less than 6%. The novelty of this technique is the prediction of the rheological properties in real time based on the caliper variables, which will help the drilling engineers to perform a safe drilling operation and eliminate the common drilling problems.

Reducing the filtrate volume and eliminating the solid invasion is very important and critical in drilling tight reservoir. This will eliminate water blocking which is the common problem in drilling tight gas formation.The objectives of this study are to evaluate the effect of using sodium silicate, assess the changes of the rheological properties of water-based drilling fluid, determine filtrate volume and filter cake thickness, and optimize the concentration of sodium silicate to be used.The obtained results showed that there was no effect of adding sodium silicate to the drilling fluid on density and pH. At room temperature, the optimum concentration of sodium silicate was 0.075 wt.% wt. which no change was observed in the yield point plastic viscosity ratio and at the same time, the plastic viscosity, yield point, and gel strength were enhanced. At higher temperature 120 and 170℉, the optimum concentration of sodium silicate was 0.075 wt.% which enhanced the rheological properties of the drilling fluid. Sodium silicate worked as a catalyst and as a result, it enhanced barite solubility at 200℉. The cumulative filtrate volume was decreased by 53% when using 0.075 wt.% of sodium silicate and the filter cake thickness was decreased by 65%. The retained permeability was 100% and the CT number before filtration and after removal was very closed, confirming no solid invasion was observed in the core.

The Khafji and Ahmadi shales in Saudi Arabia are highly dispersive, tectonically stressed formations and tend to result in wellbore instability after prolonged exposure to conventional water-based drilling fluid systems. These time-sensitive formations can cause sloughing shale, packing off, extreme over pull, back reaming, stuck pipe, and in some instances bit and stabilizer accretion, resulting in non-productive time (NPT) to operators. Some off-set wells experienced lost time of up to 30 days, and after failing to continue with conventional water-based drilling fluid, the operator had to plug back and use oil-based drilling fluid to finish the wells. Historically, a standard KCl/polymer/asphalt system was used to drill these shale sections, but due to related NPT and an extensive evaluation program planned for a candidate well, the need for a more robust fluid was identified. Oil- or synthetic-based drilling fluids were not desired due to logistical and environmental concerns. In this challenging well, the operator planned to cut five cores across a series of formations to complete the geological studies previously hindered due to shale-related wellbore problems. These demanding objectives and the notorious history of the field, required a novel solution that could control the formations while maintaining an excellent environmental and logistical footprint. This paper presents details of the successful application of a new high-performance water-based drilling fluid (HPWDF) system using a unique triple inhibition approach to stabilize troublesome zones. In this new system, a proprietary polyamine-based shale hydration suppressant, a unique low-molecular-weight encapsulator, and a co-polymeric nano-sized pore-sealant additive worked in synergy to achieve oil-based fluid performance. In the field application, the system exceeded the operator's expectations, with no fluid-related downtime and successful execution of five coring runs. After coring and logging, casing was run and cemented smoothly, even after 42 days of wellbore exposure. With similar formations drilled across the Middle East, this solution has the potential to be used as an environmentally-friendly alternative to oil-based fluids in the Middle East.

This paper presents a customized water-based drilling fluids design for drilling challengig sections through varying formations. The offset wells were reviewed to identify the issues while drilling the trajectory through troublesome reactive and depleted formations that showed wellbore stability issues, stuck pipe incidents, and induced severe losses.Additional problems experienced while drilling include shale dispersion, resulting in fine solids buildup in the drilling fluid, and the adherence of shale to the drill pipe and bit, reducing penetration rates. The customized drilling and completions fluids system was designed for different intervals. The system was developed with the following objectives in mind: improved hole stability through reactive formations; enhanced hole-cleaning efficiency at critical angles; minimized risk of stuck pipe across depleted formations with high porosity and permeability; minimized or non-induced losses to formation utilizing a unique wellbore strengthening technique; and improved rate of penetration to optimize drilling efficiency.This paper describes the customized high-performance water-based mud (HPWBM) design and performance. A comprehensive engineered approach addressed the challenges of drilling horizontal wells by using a high-performance aluminum complex and polyamine chemistry to improve wellbore stability.This approach for drilling fluid chemistry provides an alternative replacement for previously used nonaqueous drilling fluids. Three wells were drilled successfully, and the lessons learned on these wells were incorporated in drilling subsequent wells to continue improving drilling performance.

For decades, wells targeting the Rotliegend reservoir in the Southern North Sea Basin have been drilled using conventional water-based mud (WBM) in the top hole section and oil-based mud (OBM) systems throughout the remaining sections of the well. The standard well design generated high waste disposal costs onshore and offshore, particularly with regard to OBM waste. This study evaluates alternative fluid systems to help reduce disposal costs for the operator. As part of the operator's environmental improvement strategy, the operator and fluids provider team identified potentially significant waste disposal cost savings for an onshore trial. Using a WBM system for drilling top holes as well as through the lower sections could result in cost savings through the reduction of top hole fluid dilution as well as a reduction in waste disposal costs. A high-performance water-based mud (HPWBM) system with similar performance to an OBM system was proposed as part of a trial to demonstrate these potential savings in disposal costs for an onshore well. The field trial was a great success compared to conventional fluid systems and methodologies. The well was drilled 11.6 days ahead of schedule and 20% under the planned budget. The time vs. depth curve was on par with what was expected when drilling with an OBM system. The HPWBM system created a saving of >5% of the total well cost and it was 16% less expensive than conventional fluid systems. A further saving of 2.5% of the total well cost was identified for future onshore/offshore applications of the HPWBM system. It was also theorized that a further reduction in waste disposal costs could be realised in offshore operations. The field trial was based on a basic onshore well trajectory as a proof of concept. Upon the success of using HPWBM in the basic well, more challenging onshore as well as offshore applications would be examined which have the potential to double the cost savings generated. This novel approach of using an environmentally acceptable HPWBM system in the Southern North Sea Basin can offer significant cost saving opportunities with regard to waste management for both onshore and offshore wells compared to conventional WBM and OBM systems.

The primary cause of wellbore instability is the interaction of water based mud with shales which usually involves the movement of water and ions into or out of shale thereby causing alterations in mechanical property of the shale resulting in dispersion of shale particles into the mud. This work involves experiments to analyze the effects of chemical osmosis, diffusive flow prior to shale hydration and inhibition, determination of the effects of salt addition on pH and density of mud and also determination of the effect of Temperature and pressure other than just temperature on dispersion of shale cuttings into water based mud. It also shows the behaviour of shale in various inhibitive agents e.g NaCl, KCl, CaCl2 and Polymer XCD when being hot rolled. Results from experiment performed in this work confirmed that osmosis and ionic diffusion play a great role in shale hydration and dispersion. It also showed that subjecting the system to temperature and pressure conditions other than just temperature caused more dispersion of shale into mud. KCl was the best inhibitive agent as more shale cuttings were recovered from the mud while the least shale recovery was from CaCl2/salt formulation. A further experiment was performed by adding polymer XCD to the Salt/mud formulations so as to investigate its inhibitive capability; result showed that more shale cuttings were recovered as compared to when only Salt/mud was used.

Shale-gas plays have gained significant importance in China. Sichuan Basin, industry's primary focus for shale gas, has finished hundreds of wells. The employed drilling fluids for drilling shale horizontal wells here are mostly oil-based muds (OBMs), due to its well-known excellent performance and the considerable geologic structural complexity. With the implementation of new national environmental law, the application of OBMs will be limited. A pressing goal is to develop a high-performance and environmental-friendly water-based mud. This paper discussed the research and application of a novel high-performance water-based mud for shale gas horizontal wells in Zhaotong area of Sichuan Basin. The morphology, mineralogical composition, Porosity and cation exchange capacity of the shale samples, and the key technical problems in the target formation were first analyzed. Then, a novel hybrid silicon shale inhibitor, rigid nano-polymer plugging agent, liquid filtrate loss control agent and liquid lubricator were prepared, respectively. Incorporated with other selected agents, an innovative water-based drilling fluid (HPWBD) with a density of 2.2 g/cm3 was formulated and applied. Extensive lab work was carried out to compare the properties of HPWBD with field oil-based drilling fluid. The results show that HPWBD had excellent inhibitive and lubricant properties, closing to the oil-based drilling fluid. Besides, HPWBD was highly plugging and rheology stable after rolling at 100 oC under high density conditions. Then, the HPWBD was applied successfully in Huangjinba YS108H4 well. The drilled horizontal well interval reached a length of about 1500 m. During drilling, no downhole troubles were observed, no bit balling was found, the borehole diameter was regular, and the electrical logging operation was successful just at the first time. Meanwhile, it reduced cost and environmental concerns associated with cuttings transportation and disposal. In a word, the developed high-density water-based drilling fluid showed outstanding performances, closed to oil-based muds. Moreover, it was beneficial to the environment and could reduce the cost significantly. It will provide an alternative to oil-based mud for safe and environmental development of shale gas in China.

The migration from water-based drilling fluids in the 1990s to predominately synthetic based drilling fluids in the 2000s by a major operator in the Niger Delta was not predicted on any scientific research on the effects of water based drilling fluids on borehole stability. In spite of this migration, the operator continued to have borehole stability problems in field X. In addition the cost of drilling fluids continued to rise to about 10% of the well cost in field X. Also there has been increasing stringent requirements by the regulators on the use of synthetic based drilling fluids. This paper describes the results of the investigation on the possibility of using water based drilling fluids to drill the deeper sections of wells in field X. The overall intent of the investigation is to reduce the drilling fluid cost and improve the environmental and regulatory performance of the operator. The project methodology consists of two approaches. First is a study of borehole stability problems in the project area. The second method consists of experimental studies of the field X formation samples to determine the mineralogy of the formations. Based on the study, a water-based mud system that could be used to drill these formations was developed. The result of the borehole stability study showed that borehole problems occurred in wells drilled with water based mud and as well as those drilled with pseudo-oil based muds. The experimental studies showed that the highest percentage of the smectites/illite reactive clays in the samples examined was 12%. Use of 7% KCl solution caused a reduction in the shale reactivity by as much as 39.6%. Use of a 9% KCl with 8% base oil water-based fluid led to a very low clay dispersion of 6.5%

Drilling with water based mud (WBM) generally has its green and cost effective advantages but also comes with its own challenges, which raise the need for more vigilance, planning and timely reaction when WBM is to be used for any hole section. On FAQ1X well, the 16″ top hole section was drilled to 9,500fttvd with KCl polymer WBM; while circulating hole clean in preparation for tripping out, erratic mud rheology properties were observed. It took up to 3days to recondition the drilling fluid specifications. An investigation was carried out to explore the possible causes. The behavior bore no similarity to equivalent sections in previously drilled wells, though the mud system was different. The fresh water for building the mud was optimum; the additives were in good condition and within acceptable operating conditions. The analysis for any carbonate contamination by Alkalinity Analysis (which is rather unreliable) gave an indication of possible carbonate contamination though no source of carbonate was detected. The bentonite used was not in excess yet there was an increase in the Cation exchange capacity of the mud. The other source of Low gravity solids is formation solids that have been very well grinded by the bit and dispersed in the mud such that it becomes difficult to separate them from the mud system via the mud cleaning equipment. They lead to severe gelling of the mud and consequently high mud rheology and hole-swabbing tendency. This significant distortion in rheological properties of the mud was as a result of high solid content in the mud and possibly carbonate or bicarbonate. A dilution recipe was developed and applied to tackle both possibilities and the mud properties were restored.

Abstract This paper describes the use of an innovative high-performance water-based drilling fluid system in south Europe. The novel drilling fluid allowed to successfully drill a sidetrack in a deep, high pressure-high temperature (HP-HT) well, in an area where low toxicity oil-based drilling fluids had been used in the past, due to the adverse drilling conditions. Comprehensive laboratory testing carried out to customize the drilling fluid formulation during the well planning phase, was complemented by further testing conducted during drilling operations. An obvious advantage of this system is its simplicity. It is composed mostly of liquid additives that allow a quick and easy preparation at rig site. The system is also compatible with the full range of mud densities, while exhibiting consistently superior lubricity characteristics. A tailored version of the system for this sidetrack well in southern Europe, required a heavy weighted fluid (up to 2.06 SG) to provide sufficient hydrostatic pressure for well control. The formulation included a high temperature rheology modifier that improved fluid stability at temperatures up to 160°C at total depth. A high performance lubricant was added to the system to improve drilling rate, while using an advanced steerable drilling system. Lubricity coefficients were monitored and recorded daily at rig site using a standard industry accepted ring and block type lubricity tester. The lubricity values fell in the range traditionally associated with oil-based mud usage. The successful sidetrack operations were completed with very good performances. Introduction Drilling fluids can influence all processes of well construction and operation, since incompatibility between the selected fluid and geological conditions yields many undesirable consequences in terms of drilling issues, quality of the production zone and economical performances. This is even more "true" when operating in complex drilling conditions, such as those described in this paper. In particular, one of the first applications of an innovative high performance water-based mud (HPWBM) outside the United States - it had been previously used only once in Europe - is reported herein, which made it possible to successfully drill a challenging sidetrack within a deep, high pressure-high temperature (HP-HT) well, in hard and tectonically-stressed formations. The HPWBM, optimized to the specific field conditions, met several standards for effectiveness: high lubricity, stability at high temperatures, little tixotropy, resistance to solids contamination. The fluid represented a big step forward in reducing the environmental impact, while providing performances comparable to those of low-toxicity oil-based muds used in the area for the last 20 years, as the only means to overcome the difficult drilling conditions. The reservoir is characterized by a white light brown dolomite of the Triassic age, and has two main hydrocarbon zones, an upper and a lower one. The sidetrack's target was the upper reservoir, which is an isolated fault block in the west area of the field resulting from a series of tectonic discontinuities, that had remained undrained by the previous operations. The depth of target reservoir was between 5500 and 6000 m, with a temperature of up to 160°C and pressures over 1000 kg/cm2 at total depth. In the offset wells, these demanding conditions, combined with the high formation hardness and the significant tectonic stresses, had leaded to such drilling issues as high torque, low rate of penetration (ROP) and wellbore instability. Instead, in the case described in this paper, the usage of the HPWBM, in combination with an advanced steerable drilling system, enabled the sidetrack to be successfully executed without incidents.

Abstract Unconventional resources include oil and gas present in shale, tight sandstone and tight limestone formations. Shale oil can be produced from deposits of shale with estimates of about 5 trillion barrels of oil in place around the world. Because of the high content of clay in the shale formations, water-based drilling fluids tend to cause wellbore instability problems when drilling this type of formations. When it comes in contact with water, clay starts to react, swell and/or disperse leading to shale disintegration and sloughing. As a result of shale sloughing down into the borehole, cleaning efficiency of drilling fluids decreases significantly. Moreover, tight hole problem is expected which may cause drillpipe to get stuck and, as a result, increases non-productive time and well construction cost. Several types of shale inhibitive drilling fluids were developed using different shale inhibitors and stabilizers. Developing an inhibitive drilling fluid with long-term inhibition can eliminate the need for unnecessary casing and reduce tripping time. Multiple formations including the shale formation can be drilled and cased in one hole section. This paper summarizes preliminary laboratory testing results for characterizing one shale sample and assessing the interactions with different water-based mud systems. Shale characterization included determination of mineralogical composition using X-ray diffraction and determination of cation exchange capacity (CEC) while shale-mud interactions evaluation included swelling, dispersion and inhibition durability tests. Introduction Unconventional resources refer to any petroleum resource that can not be recovered and produced using conventional methods. Examples include: shale gas, tight gas and shale oil. These resources exist in shale and tight sandstone formations with very low permeability. Therefore, hydraulic fracturing is usually necessary to produce at economic rates. Shales represent a large portion of the unconventional resources in Saudi Arabia. While conventional shale formations are the source rock for oil and gas, unconventional shale formations are the source rock and the reservoir at the same time. The well is drilled and completed into the shale zone. Since conventional water-based mud systems (WBMs) cause shale instability, there is a need to develop inhibitive water-based muds that provide the required long-term shale inhibition especially when drilling development wells horizontally through shale formations to exploit unconventional resources. Although drilling with oil-based drilling fluids can provide better shale inhibition, higher penetration rates and good lubricity, the environmental regulations and the high cost of such fluids make it difficult to justify the decision to drill long horizontal shale sections with these fluids. Shale formations are characterized based on clay content and composition. Clay minerals are grouped mainly into five groups: kaolinite, smectite, illite, chlorite and vermiculite. Previous experimental work showed that smectite group has the highest reactivity and sensitivity to water compared to the other groups from swelling point of view. Because the degree of reactivity depends on the shale composition and, also, shale composition differs from one area to another, it is necessary to do shale characterization before an inhibitive drilling fluid is recommended for a certain shale formation. Shale characterization includes determining the clay content and reactivity as well as determining the water activity of the shale sample. Chenevert (1970) conducted a laboratory work utilizing the drilled cuttings to measure the water activity of different shales based on the adsorption characteristics. Isotherms for adsorption and desorption were established after drying and placing shale drilled cuttings in a desiccator and allowing them to reach equilibrium. Based on the isotherms and the weight percentage of water in the shale, a scale from 0.1 to 1.0 was suggested for the water activity.

Although many shale oil wells have been drilled in recent years, the industry as a whole is still at the beginning of the learning curve with respect to shale oil drilling operations. Drilling through shale oil formations can be problematic and impose significant costs to operators attributed to wellbore stability problems. These problems include but are not limited to tight holes, stuck pipe, fishing, sidetracking, and well abandonment. Therefore, to more efficiently and effectively drill through such formations, operators should better understand their properties. So far, few experiments have been conducted on shale oil rock samples to better understand their properties while drilling using oil-based mud (OBM). Most experiments have been performed on common shale core samples, which are significantly different from oil shale samples in terms of mineralogy, cation exchange capacity (CEC), pore fluid, and swelling properties. This study investigates the swelling properties and CEC of shale oil core samples from the Eagle Ford field in the laboratory. Specifically, scientists submerged samples in 7% potassium-chloride (KCl) brine and OBM and then used strain gauges and the V-Shay data acquisition system to record both lateral and axial swellings for submerged and non-submerged areas. They then compared the effects of drilling fluid on the swelling properties of the rock samples and, consequently, on borehole stability during drilling operations. All of the experiments were performed in an environmental chamber, which allowed maintaining a constant temperature. The samples were taken from the vertical, horizontal, and diagonal (45°) directions relative to the layering to help determine the optimum well path that would encounter the least possible wellbore stability problems associated with swelling during drilling operations. The results demonstrate that the swelling properties and CEC of the shale oil core samples are different from the common shale core samples. The study quantified the shale/fluid properties, interactions, and effects of the different fluids on rock properties in unconventional reserves. The results of the study can help drilling engineers more precisely understand unconventional shale oil rock properties. The results of the study should also help design a more effective drilling fluid for field applications, as well as more accurately predict the mechanism of formation failure.

Organic polymers are commonly used to control filtrate loss in water-based drilling fluids both in circulating and non-circulating periods during drilling operations. In Nigeria, the over dependence on these polymers to achieve this function of drilling fluid is worrisome on the overall well drilling cost. Therefore, a substitute for these polymers with locally available materials is indispensable. In lieu of this fact, an agro by-product, rice husk was evaluated as a possible filtration loss control additive in water-based drilling mud and the results compared with sodium carboxymethyl cellulose (CMC) and polyanionic cellulose (PAC) using static fluid loss measurement approach. The results obtained depict that with a concentration of 20g content of rice husk to 350mL mud (about 20lb/bbl) there was a decrease of 64.89% in fluid loss compared to 62.77% and 59.57% for CMC and PAC respectively at a content of 10g per 350mL mud. Additionally, filter cake thickness measurement from the husk showed a decrease of 3.03% and 8.57% respectively when compared to CMC and PAC. Thus, exploitation of rice husk as fluid loss control additive in water-based mud would be a welcome development in the oil and gas industry since its characteristics of high resistance to water penetration and thermal stability would be applicable to deep wells where high temperature is anticipated since CMC and PAC temperatures degrade at this condition.

Description of Proposed Paper As the drilling industry moves towards extended-reach wells in more challenging formations, the need to identify operational solutions (e.g., drilling fluids/lubricity additives) to reduce friction, torque, and drag has become more important. Additionally, as the industry looks to maximize the use of water-based drilling fluids (to benefit from lower drilling fluid costs and improved environmental profile), the need to find novel additives that can improve lubricity has become more pressing. However, current methodologies for reducing downhole friction in horizontal wells generally involve reactive addition of lubricant products that are broadly acting, that may adversely affect the rheology of the fluid system, or that may dissipate or degrade over time. To address the need for new additives, a novel biotechnology method for encapsulating oil in polysaccharide-based polymers has been developed that selectively delivers high pressure lubricants at areas of high shear, pressure, and friction (e.g., between the drill string and formation or casing and also between drill bit and formation). Application Due to the protection afforded by encapsulation, this targeted friction inhibitor can be proactively added to water-based drilling fluid systems, where it circulates through the system until conditions are met to break the capsule and release lubricant. Observations in laboratory and field testing suggest potential operational improvements in running casing, reduction of torque/drag, reduction of bit balling, and faster Rate of Penetration (ROP) from targeted lubrication. Results, Observations and Conclusions Our characterization of encapsulated oil has shown the ability to reduce the coefficient of friction by over 80% in water-based mud formulations in the laboratory. In field-scale testing at the Catoosa Testing Facility, we have observed reductions in drag of up to 50%, reductions in torque of up to 45%, and up to 20% improvement in Rate of Penetration (ROP) in horizontal drilling after addition of encapsulated oil to a water-based polymer mud system. These results were substantially improved relative to observed results in an exploratory field well, in which ROP increased by up to 216% after addition of encapsulated oil in a saturated sodium chloride drilling fluid system. Significance of Subject Matter Our field testing and characterization in the laboratory and field have demonstrated the utility of adding encapsulated oil to a water-based mud-system to drill horizontal wells to improve the operational efficiency of drilling.

Erosive and abrasive wear effect of water-based drilling fluid (WBM) on down-hole tools may reduce the service life of down-hole tools, and its magnetic contamination on Measurement-While-Drilling (MWD) directional tools may cause azimuth errors and reduce the wellbore position accuracy. The erosive and magnetic effects would be worse when a high density WBM densified with a high content weighting agent was employed. One of the main reasons of the erosive and magnetic effect is related to the weighting agent used. To reduce the erosive effect and magnetic interference of weighting agent, a micronized barite as a new weighting material was prepared in this paper, and then characterized by scanning electron microscope (SEM) and laser particle size analyzer. The prepared micronized barite, as a new weighting agent of high density WBM, has great promise to reduce the drag, erosion and magnetic interference along the horizontal section of large extended-reach wells and horizontal wells. It can also be used in HTHP wells and coiled tubing drilling technology. In our experiments, two conventionally weighting agents, barite and hematite were chosen to as the comparing samples. The erosive effects, magnetic contaminate tests, lubricity and rheological properties of high density WBM weighting with micronized barite, barite and hematite were evaluated on erosion instrument, a fluxgate magnetometer, an EP lubricity tester and a rotational viscosimeter, respectively. It was found that the high density WBM weighted with micronized barite showed less erosion, lower magnetic susceptibility, similar or better rheological properties, and smaller lubricating coefficient than that weighted with hematite or barite. Comparing with hematite or barite, the micronized barite could effectively reduce erosive wear on down-hole tools, reduce magnetic contamination on MWD directional tools, and control the rheological property of high density WBM, which would significantly contribute to the service life of down-hole tools, the wellbore position accuracy and the safety of drilling operations.

A sizable amount of literature exists analyzing the effect of confining stress on fracture conductivity in sandstones. This report attempts to answer similar questions with regard to shale formations. The low Young's Moduli and Brinell hardness values characteristic of many prospective shale formations may lead to a great deal of embedment and fines production which can drastically reduce fracture conductivity. Furthermore, shales exhibit sensitivity to aqueous fluids which may cause them to be weakened in the presence of certain fracturing fluids. Previous work analyzing shale fluid sensitivity has failed to preserve the shales’ formation properties by allowing the shale to dry out.This paper presents a study of propped fracture conductivity experiments at reservoir temperature and pressure using various North American shale reservoir cores. Exposure to the atmosphere can alter the mechanical properties of the shale by either drying or hydrating the samples, so care was taken to preserve these shales in their native state by maintaining constant water activity (relative humidity). Variations in applied closure stress and aqueous fluid exposure were analyzed and in certain cases altered the propped fracture conductivity by crushing proppant, embedding the proppant into the fracture face, and producing fines. The damage to fracture conductivity is correlated to mineralogy for the various shale samples. These findings show that a one-size-fits-all frac design will not work in every shale formation, rather a tailored approach to each shale is necessary.In the future, the results of this work will be analyzed alongside easier to perform Brinell hardness tests, swelling tests, and other characterization techniques incorporated into the UT Shale Characterization Protocol (Zhou et al., 2013). Correlations were developed to relate the simpler tests to the fracture conductivity experiments will yield an easier method to determine the role embedment and fluid sensitivity have on post treatment fracture conductivity in shales.

Abstract Drilling operations in salt zones have gained importance in Brazil due to the discovery of large oil and gas reserves in the Pre-Salt area. Thus, the pursuit of excellence in such operations is requiring considerable development of new operational practices and technologies. Synthetic base mud has been the first choice to drill through evaporite sections in Pre-Salt zones. Synthetic fluids application practically eliminates salt dissolution and improves caliper quality. However, depending on the salt mobility rate, stuck bit and/or stuck pipe can happen, demanding the injection of fresh water pills for its liberation. In some wells, the frequent use of those pills resulted in enlarged sections. The situation gets worse in scenarios where loss of circulation is a major issue. On the other hand, the use of non-saturated aqueous fluids to drill soluble salts (e.g. halite, tachyhydrite and carnalite) can result in localized enlargements due to leaching process. Drilling a gauge hole is a very important issue to prevent wellbore collapse and/or problems in cementing operations. However, high operating costs associated to deep water drilling is placing additional emphasis on drilling performance in order to reduce the operational time, without losing the quality of the wells. This concern raises the issues of how to most effectively improve operational performance regarding the drilling fluid selection. The paper presents the results of the use of water based muds in the drilling of two offshore wells in Brazilian Pre-Salt area and highlights the lessons learned from the experience. Before the field application extensive lab tests and numerical simulations were carried out to support the drilling fluid design for the wells. In the first well, differences between the planned and encountered drilling conditions led to fluid replacement during the operation. On the other hand, in the second well, 2.000 m salt extension was successfully drilled to depth with no major operational problems and good drilling performance. The field application of WBM proved to be a good option to drill the salt layers in the development of Pre-Salt fields but it demands a more detailed knowledge of both lithology and stratigraphy of the evaporite section. Introduction The drilling fluid design for salt zones uses to focus on drilling a gauge hole to prevent wellbore collapse. Due to solubility issues, synthetic based emulsions have been selected as the first option to drill through evaporite layers in the Pre-Salt scenario. However, high operational costs associated to deep water drilling have brought special attention to drilling rates in order to reduce operational time without loss of well quality. In offshore drilling operations, the use of synthetic based drilling fluids demands the use of centrifuges to clean the cuttings before they are discharged into the sea. This procedure results in strict control of penetration rates due to cuttings processing issues. Moreover, in scenarios where lost circulation is a major issue the use of synthetic base muds may not be the best choice. Therefore, the challenge is to find the best way of effectively improving operational performance through an adequate drilling fluid selection. And it raises the question: should water base mud (WBM) or synthetic base mud (SBM) be used? In Brazilian Pre-Salt scenario, the most common salts encountered are halite (NaCl), carnalite (KCl. MgCl2.6H2O), tachyhydrite (CaCl2.2MgCl2.12H2O) and anhydrite (CaSO4). The deposition sequence normally is the opposite of the salt solubility in water which, for these salts, follows the same sequence of easiness of reaction with water: Tachyhydrite > Carnalite > Halite > Anhydrite. So, they might dictate some formulation choices to avoid dissolutions. In that aspect, the synthetic fluid is preferred over water based muds, because it neither has free water nor interferes in the crossed salts solubility. The well caliper tends to be in gauge when compared with the saturated water base fluid.

Screening for Enhanced Oil Recovery (EOR) processes is a critical step in evaluating future development strategies for depleted reservoirs under primary and secondary recovery. However, selecting the optimum EOR process for a given reservoir is challenging because it requires evaluating and comparing performance for various EOR processes, which is complex and time consuming. This paper presents a new EOR screening model that can predict the performance of various gas- and water-based EOR processes based on simple reservoir properties. The model estimates the oil recovery from miscible and immiscible gas/solvent injection (CO2, N2, and hydrocarbons), low salinity water flood, polymer, surfactant-polymer, alkaline-polymer and alkaline-surfactant-polymer floods. The screening model is based on a set of correlations that were developed using the response surface methodology, which correlates the oil recovery at dimensionless times to the important reservoir and fluid properties and EOR process variables identified for each process. The results of the model have been validated against a number of field test and numerical simulation results. The screening model provides the capability to screen a large set of reservoirs for a wide spectrum of EOR processes, to identify the good EOR targets and the optimum EOR process for the target reservoirs. In addition, this model easily performs sensitivity analysis without the need for numerical simulations, allowing teams to account for uncertainty in reservoir properties and optimization of flood design. Finally, the methodology can be applied for developing screening models for other oil recovery mechanisms such as thermal (steam injection, SAGD), microbial EOR and other methods.

The growing demand for well-designed weighting agents to overcome the currently drilling challenges such as ECD management and the settling tendency of the weighting agents led to the development of a new micronized ilmenite (FeTiO3). The acid solubility of ilmenite is of great importance to remediate any damage that might occur during its use in the drilling operation.Extensive lab work was conducted to: 1) assess the reaction of 10 wt% HCl with ilmenite particles at 300°F and 300 psi using an aging cell, 2) optimize the concentration of HCl to remove the filter cake using a modified HPHT filter press at 250°F, 3) determine the removal efficiency of the filter cake, and 4) calculate the retained permeability of Indiana limestone cores.The reaction of hydrochloric acid with ilmenite showed that HCl (10 wt%) dissolved 75 wt% of the iron from ilmenite particles after 10 hrs of reaction at 300°F. SEM and XRD results showed that the reaction product was mainly rutile (TiO2) after 6 hrs of reaction.Ilmenite-based filter cake was removed completely after reaction with 5 wt% HCl (300 g solution) for 16 hrs soaking time at 250°F. The retained permeability of the Indiana limestone and Berea sandstone cores was nearly 100% after HCl treatment (5 wt%). Removal of ilmenite water-based filter cake is a simple process as compared with barite water-based filter cake, which cannot be removed using HCl. This study will provide a complete evaluation of the reaction of HCl with ilmenite and will help the drilling and completion engineers to better design the chemical treatments to remove the filter cake for HPHT wells.

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.

Ecuador is producing oil today from mature fields with increasing water cut, and most of the reservoirs are subhydrostatic with permeability ranging from 10 to 1000 md and significant clay content (mainly kaolinite and glauconite) in the formation matrix. As a consequence of the increasing workover interventions and fluid invasion due to the depleted reservoir conditions, there was need to stimulate the wells to be able to bypass the damage zone. In the past, it was common to lose completion fluid into the reservoir, resulting in a 20% to 50% reduction in production or even in extreme cases killing the well when the completion fluid was incompatible with either reservoir fluids or formation clays. Historically matrix acidizing treatments have been perfomed in an attempt to remove formation damage or to increment production, with limited success. Matrix acidizing treatments are not sufficient to fully remove the damage because of the high clay content, and in many cases, the damage cannot be removed by just treating the critical matrix. Conventional hydraulic fracturing treatments were then tried as a means to bypass the damage. However, some of the wells treated showed positive skin factors following the fracture treatments. The wells in which hydraulic fracturing had proved unsuccessful were studied in more detail to understand the reason why hydraulic fracturing resulted in a positive skin. It was concluded from the formation mineralogy and core flow testing that the fracturing treatments were unsuccessful due to a reduction in the formation permeability due to the mechanical plugging and movement of the kaolinite or disrupted mica in the pore throats. The reduction in the matrix permeability results in skin damage in the faces of the fracture. The fracture-face damage or skin can also be caused by fluid loss from the fracturing fluid through the fracture faces, which creates an additional drop in pressure that may further reduce the productivity of the well. The impact of these effects on the productivity of a treated well depends on the reservoir characteristics and mineralogy, fracture geometry, extent of fluid leakoff into the reservoir, and the viscosity of the fracturing fluid filtrate. The magnitude of these effects and resulting additional pressure drop generally increases with increasing reservoir permeability. To eliminate or mitigate the fracture-face skin effect in water-sensitive formations, a new treatment incorporating a prepad of a viscosified blend of chelants and acid was field tested. By adding this stage into the fracturing treatment design, the retained matrix permeability was increased to +/- 70% of the undamaged matrix permeability, resulting in negligible fracture-face skin. The productivity of fracturing treatments performed using this innovative technique resulted in negative skin factors and production ratios that exceeded expectations in water-sensitive and high clay content reservoirs.

Historically, invert-emulsion drilling fluids are the system-of-choice for drilling offshore Cameroon due to minimum NPT, high ROPs, ease of maintenance, robust performance under various downhole conditions, and the resulting lower drilling costs. However, with a regulatory environment moving toward zero discharge, the cost of the waste management associated with invert-emulsion drilling fluids is diminishing their attractiveness. Therefore, when the operator was planning to drill their next development well offshore Cameroon (BaF field, Douala Basin), they evaluated high-performance water-based mud system (HPWBM) alternatives. HPWBM systems offer the potential advantage of offshore discharge of drilled cuttings and effluents due to absence of oil contamination and lowered waste management costs. This paper documents the advantages of the selected HPWBM, and its design and performance characteristics in stabilizing reactive clays/shale. Specially designed chemical components in the HPWBM formulation created an efficient osmotic membrane, thereby minimizing pore pressure transmission under downhole conditions. This HPWBM system is one of the first commercial applications of nanotechnology in drilling fluids. The field recap demonstrated that the selected high performance water-based drilling fluid met expectations by achieving the required drilling performance and high shale stabilization with zero environmental impact. Finally, the paper reviews the cost reduction in waste management when switching to the environmentally friendly high performance water-based mud system.

This paper discusses the outstanding performance achieved in a deep HPHT Jurassic formation drilled using Potassium Formate based fluid. This paper also describes methodology adopted for short term testing and stimulation of an exploratory well and finally the field results. Drilling and completion of deep Jurassic formations in the state of Kuwait is generally done with Oil Base Mud (OBM) weighted with Barite. During drilling, barite causes significant formation damage to the carbonates with natural fractures and it is essential to stimulate the well to evaluate the real reservoir potential. Formation damage is usually treated with matrix acid stimulation, however barite does not respond to acid. Kuwait Oil Company (KOC) was in search for an alternative drilling fluid causing relatively less formation damage and also responds to remedial actions. Potassium Formate brine with suitable weighting agent to achieve sufficient mud weight around 16ppg was selected for field trial in one of the exploratory wells. Formate based brine is a high-density Water Base Mud (WBM) which maintains rheological stability at high temperature and minimizes formation damage. Last 2,000 feet in 6" hole section of 18,000 feet well was drilled using 15.9 ppg Potassium Formate WBM. During short term testing, acid wash alone was sufficient to remove the formation damage and productivity has tripled which is unlikely in case of wells drilled with OBM. This case study shows how Potassium Formate based mud enhanced the productivity and reduced the testing time and cost. Based on the successful field test results, it is planned to drill future Jurassic deep formation with Potassium Formate based fluids in future.

Historically, shale instability is a challenging issue when drilling reactive formations using water-based muds (WBM). Shale instability leads to shale sloughing, stuck pipe, and shale disintegration causing an increase in fines that affects the rate of penetration. To characterize shale instability, laboratory tests including Linear Swell Meter (LSM), shale-erosion and slake-durability are conducted in industry. These laboratory tests, under different flow conditions, provide shale-fluid interaction parameters which are indicative of shale instability. The composition of WBM is designed to optimize these interaction parameters, so that when used in the field the fluid helps achieve efficient drilling. This paper demonstrates modeling of shale-fluid interaction parameters obtained from the LSM test. In the standard LSM test, a laterally confined cylindrical shale sample is exposed to WBM at a specific temperature and its axial swelling is measured with time. The swelling reaches a plateau which is characterized by a shale-fluid interaction parameter called % final swelling volume (A). A typical LSM test runs for around 48–72 hours and many tests may be needed to optimize fluid composition. In this work, a method/model is developed to predict final swelling volume (A) as a function of the Cation exchange capacity (CEC) of the shale and salt concentration in the fluid (prominent factors affecting shale swelling). An empirical model in the form of A = f(CEC)*f(salt) which describes the explicit dependence on the influencing variables is developed and validated for 16 different shale samples at various salt concentrations. This model would significantly reduce LSM laboratory trials saving time and money. It could also enable rig personnel to obtain quick measure of shale characteristics so that WBM composition could be adjusted immediately to avoid shale instability issues.

Hydraulic fracturing in the Bakken oil reservoir on the Canadian side of the Williston basin involves a risk of connection to the overlying water bearing formations. The Bakken reservoir is a tight dolomitic siltstone which requires multiple stage hydraulic fracturing in horizontal wells to achieve economic oil production rates. Within ten to fifty meters above the Bakken reservoir there often is a higher permeability water bearing interval in the Lodgepole limestone formation. If hydraulic fractures connect to the higher permeability interval in the Lodgepole, then water production and associated handling costs would greatly increase. Any loss of fracture fluid and proppant to the Lodgepole could also reduce effective fracture length within the Bakken and subsequently lead to lower oil production rates. To minimize the potential negative impact of partial hydraulic fracture growth out of zone, several strategies have been used. Some of these strategies include reduction of pump rate, slurry volume and fluid viscosity. Minimizing fluid viscosity without significantly reducing proppant suspension can be a challenge. To address this issue, a unique synthetic polymer water based fluid system with excellent proppant suspension characteristics has been field tested. This system has a viscosity between that of linear gel and typical crosslinked systems and has a unique breaking process. This fluid system has been used in multiple Bakken wells for over one year and field production results will be reviewed to demonstrate the effectiveness of the combined strategies in reducing water/oil ratios. The impact on oil production rates will also be reviewed. The paper will furthermore outline several challenges with deployment in the field. Fracture geometry simulation will be used to demonstrate the expected sensitivity of fracture containment to fracture fluid viscosity and pump rate.

Low matrix permeability and significant damage mechanisms are the main signatures of tight gas reservoirs. During drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around wellbore and eventually reduces permeability at near wellbore. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves. Water blocking and phase trapping damage is one of the main concerns in use of water based drilling fluid in tight gas reservoirs, since due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formations may result in introduction of an immiscible liquid hydrocarbon drilling or completion fluid around wellbore, causing entrapment of an additional third phase in the porous media that would exacerbate formation damage effects. This study focuses on phase trapping damage caused by liquid invasion using water-based drilling fluid in comparison with use of oil-based drilling fluid in water sensitive tight gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and results of laboratory experiments core flooding tests in a West Australian tight gas reservoir are shown in which the effect of water injection and oil injection on the damage of core permeability are studied. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of reducing skin factor and improving well productivity.

Although key shale gas plays vary considerably in terms of reservoir pressure, temperature, mineralogy, and in-situ stresses, the principal drilling-related issues are wellbore stability, shale inhibition, hole cleaning and rate of penetration. Because many of the shale reservoirs are in either environmentally sensitive or densely populated areas, stricter environmental regulations will require new types of environment-friendly water-based drilling fluids. The traditional shale inhibition method through either chemical inhibition or use of invert emulsion drilling fluid is not enough to satisfy the stricter environmental requirements. This paper focuses on the lab techniques and the performance results of evaluating and analyzing an innovative water-based drilling fluid system containing nanoparticles as a physical shale inhibitor. The physical shale inhibition is achieved by plugging the pores and microfractures in shale with nanoparticles and thus preventing water invasion into the shale. A series of transient pressure penetration or flow-through tests, also known as shale membrane efficiency tests, were performed to evaluate water invasion rates into various shale core samples, with initial brine permeabilities varying from less than 1 nD to over 100,000 nD. Permeability reduction was used as a proxy of water invasion reduction and the effectiveness of plugging of pores and microfractures in shale by the nanoparticles. Many orders of permeability reduction were consistently observed for the drilling fluids with nanoparticles. Pressure increases in the near-wellbore region due to water invasion during a given time also were analytically calculated using the permeabilities for various fluids which were interpreted from these transient flow-through tests. These pressure increases then were compared to illustrate the approximate impact depth of water invasion and give an indication of shale stability and shale inhibition performance of these drilling fluid systems. Test results and pressure increase analyses showed that this new water-based drilling fluid with nanoparticles provides an entirely different type of shale inhibition by physically plugging pores and microfractures in shale and meets the strictest environmental regulations for shale gas drilling. The tests also showed that although nanoparticles alone may be effective in preventing water invasion into shale samples with no microfractures, the combination of properly formulated drilling fluid and nanoparticles of appropriate size and concentration is the key to prevent water invasion into shale gas core samples with or without microfractures.

While water-based fluids are generally preferred for drilling in environmentally sensitive locations, many are formulated with potassium chloride (KCl) to achieve good inhibition of reactive clays. The chloride ion however can be defined as a contaminant in land operations, with the potential to inhibit the growth of vegetation, and it can also be considered a potential pollutant to aquifers. In the rain forest region of the Southern Highlands of Papua New Guinea (PNG), an alternative to the KCl high performance water based fluid (HPWBF) was needed to mitigate environmental concerns, affirm the operator's commitment to sustainable operations and provide continuous improvement as required by ISO 14001. The fluid design team examined a range of alternatives and determined that potassium acetate (KAc) could replace KCl in the drilling fluid as a more environmentally acceptable inhibiting salt. Laboratory testing confirmed that the drilling performance properties of the fluid would not be impeded by substituting KAc for KCl. Experience using KAc fluids in other geographical areas was also examined to back up the laboratory testing. The original KCl-based HPWBF had historically helped reduce issues related to the longer step-out wells, directional complexity, rock tectonics, and wellbore stability in the area. The new KAc system was used equally successfully to drill seven challenging wells. Both the technical and environmental objectives of the wells were achieved without sacrificing drilling performance. The change to KAc increased the fluid cost by approximately 10% when compared to the KCl-based system, but the operator concluded that this was a good investment, considering the distinct environmental benefits. In a comprehensive review of the background to, and the successful implementation of the KAc HPWBF in to PNG Southern Highlands drilling, this paper firstly discusses the purposes of a drilling fluid. It will show how the presence of the potassium ion is regarded as essential within the drilling fluid, but the chloride ion has no discernible benefit. It considers the unique PNG Highland rainforest environment were the drilling operations occur, the local communities who live and interact with the operation, and how the operator has successfully protected this area. The drilling fluid disposal and discharge solutions in use in the Highlands operating area are discussed, how appropriate disposal solutions are selected, and how drilling fluid discharge is controlled to minimise any environmental impact. In the second half of the paper, the methods used to develop the new chlorides-free KAc HPWBF system will be discussed. Results will then be presented from the seven wells drilled with KAc HPWBF, with two previous KCl wells used as reference. It will demonstrate that along with the improved environmental acceptance, drilling fluid robustness was maintained, as was on bottom drilling performance. Finally a review of material usage and costs indicates the change to the new KAc fluid did not have as significant an impact as first assumed, as KAc concentrations within the HPWBF were optimized.

Sediment profile imaging (SPI) technology is an effective tool for offshore oil and gas environmental assessment and monitoring. This paper demonstrates how SPI was used to evaluate the impact on the sea floor of water-based drilling fluid and cuttings discharged during drilling operations at five wellhead platforms offshore Nigeria in 2010. Pre-drill and post-drill SPI surveys were performed according to an orthogonal array of 20 nearfield stations, configured at 100 m, 200 m, 500 m, 800 m and 1,200 m distance along the cardinal directions from each platform. Three far-field reference stations were located at distances of up to 10 km from each platform. In the post-drill survey, the station array was supplemented by the addition of stations at 200 m and 500 m distance from each platform in the northwest, northeast, southeast and southwest directions. The results of the surveys indicated that physical processes dominated the sea bottom environment in the study area which consisted of either muddy sediments with relatively well-developed and mature infaunal communities or fine sand where no traces of infauna were observed. Examination of over 2,000 pre-drill and post-drill SPI images indicated an absence of widespread nearfield accumulation of drilling solids on the sea floor. Out of the 100 stations where co-located before and after images were available for direct side-by-side comparison, only two stations located 100 m and 200 m distant from one platform yielded evidence of an episodic deposition event potentially linked with discharges from the 2010 drilling operations. No other indications of contemporaneous mud and cuttings discharges were found during the SPI surveys. Comparisons are made of the use of SPI technology with the results of physical, chemical and biological sampling and testing, and predictions using dispersion modeling.

Waste water-based drilling fluids have some characteristics, such as complex chemical composition, colloidal stability, high COD (Chemical Oxygen Demand), low BOD (Biochemical Oxygen Demand)/COD ratio and poor chemical and biological degradation. As a result, such treatments as biochemical, chemical oxidation or membrane separation process has the deficiency of poor adaptability, poor treatment efficiency and high running costs. This paper has studied the treatment technology of low pressure distillation process for waste water-based drilling fluids. This technology has been applied in four wells of CPOE5 platforms in Dagang oilfield. The field application results have shown that this technology used to treat waste water-based drilling fluid can efficiently reduce COD, especially has good adaptability to different kinds of drilling fluids. The treatment technology studied in this paper can treat wastewater's COD to lower than 150mg/L. The disposed waste-water can reach the class II water quality requirements of China national standards (integrated wastewater discharge standard, GB8978-1996) and can be directly discharged into sea. This technology can control the influence and harm of waste drilling fluid on marine environment and meet the requirements of offshore environmental protection.

Hydrochloric acid, organic acid, or a mixture of these acids is used to remove filter cake, which consists mainly of calcium carbonate. However, the use of these acids in horizontal and deep wells has some major disadvantages, including high and uncontrolled reaction rate and corrosion to well tubular. To overcome these problems, chelating agents are used in oil and gas wells. Extensive lab studies were done to determine: 1) the compatibility of various chelates with α-amylase at different pH values, 2) the optimum pH that should be used to remove filter cake, 3) the efficiency of filter cake removal using a modified HPHT filter press, 4) the return permeability of sandstone and limestone cores, and 5) assess the potential of formation damage using a computer tomography scanner. All of these tests were conducted at temperatures up to 225°F. The results obtained showed that chelate solutions, GLDA (pH of 3.3 - 13) and HEDTA (pH 4 and 7) were incompatible with α-amylase solutions over a wide range of temperatures. At high pH, various chelates had removal efficiency of 40% and retained permeability of 30%, which indicated formation damage. To solve this problem, 20 wt% of the chelating agents at low pH (3.3 - 4) were used to remove the filter cake without the enzyme stage. The results obtained showed that the retained permeability increased to 85% for limestone cores and 110% for sandstone cores. The removal efficiency of the filter cake was 100% for limestone and sandstone cores. CT results showed that no formation damage was observed when using chelating agents as a breaker to remove the filter cake.

Tight gas reservoirs are mainly characterized by low matrix permeability and significant damage. During drilling and fracturing of tight formations, wellbore liquid invades into tight formation and increases water saturation around wellbore and eventually reduces permeability near wellbore or adjacent to fracture wings. The damage to permeability caused by invasion of liquid into tight formation is controlled by capillary pressure and relative permeability curves. The phase trap damage is one of the main concerns in use of water based drilling or fracturing fluid, since due to high critical water saturation, strong capillary pressure, and sensitivity of tight sand to water. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formation may result in a three-phase relative permeability curves in invaded zone in presence of reservoir gas and initial water, which may differently affect damage and productivity of tight gas reservoirs. This study evaluates phase trap damage in water-based in comparison with oil-based drilled or fractured tight gas reservoir. Reservoir simulation is used to study the effect of relative permeability curves on phase trap damage and well productivity, based on reservoir and core data from a West Australian tight gas reservoir. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of improving well productivity.

Water-based drilling fluids consisting of xanthan gum, starch, sized calcium carbonate and salt particles have been used to drill horizontal wells. Available chemical methods of removing filter cake like mineral acids, esters, oxidizers, and chelating agents are limited at certain conditions. Drilling fluid was designed based on calcium carbonate particles and an ester of lactic acid. The objective of the latter is to remove calcium carbonate once the drilling operation is complete and there is a need to remove the filter cake. Extensive lab work was done to: 1) determine thermal stability of the drilling fluid (70-72 pcf) for 24 hrs, 2) characterize the filter cake using computer tomography, 3) assess potential formation damage for different rock types (limestone and sandstone) using a modified HPHT filter press, and 4) determine the removal efficiency of the filter cake and the return permeability. The results obtained showed that the drill-in fluid has stable rheological properties up to 250°F over 24 hrs. A CT scan showed that the filter cake contained two layers, one layer close to the rock surface, which contained a mixture of calcium carbonate and acid-precursor, and one layer close to the drilling fluid that contained a mixture of XC-polymer and starch. The polymer layer was removed by using 10% solution of alpha amylase. The rest of the filter cake was removed by lactic acid that was produced from the hydrolysis of the ester. The removal efficiency of the filter cake was nearly 100% and the return permeability was about 100%, when using a ratio of polylactic acid to calcium carbonate 3 to 1. The decrease in the CT number of the core after the removal process indicated that the filter cake was completely removed and no formation damage occurred. This paper will discuss the development of this new drilling fluid and will give recommendations for field applications.

Water chemistry has a profound effect on the stability of the water film and desorption of organic oil components from the mineral surfaces in a water—based enhanced oil recovery (EOR) process. By knowing the chemical mechanism for the symbiotic interaction between the active ions in seawater; Ca2+, Mg2+, and SO42—, "Smart Water" can be designed and optimized in terms of salinity and ionic composition as an EOR—fluid. In the present study, the efficiency of "Smart Water" on oil recovery in carbonate rock is summarized and discussed in the temperature range of 70—120 °C. By removing non–active salt, NaCl, from the composition of the injected seawater, the oil recovery by spontaneous imbibition was improved by about 5–10% of OOIP compared to seawater. On the other hand, an increase in the concentration of NaCl in the imbibing fluid resulted in reduced oil recovery of 5% of OOIP. A systematic decrease in oil recovery was observed when diluting seawater with distilled water to obtain a low salinity brine, 1000–2000 ppm. The decrease in the oil recovery was attributed to the reduced concentration of the active ions. When seawater depleted in NaCl was spiked by SO42–, the oil recovery increased by about 5 to 18% of OOIP compared to seawater depleted in NaCl. The amount of Ca2+ in the seawater depleted in NaCl had no significant effect on the oil recovery at low temperatures, ≤100 °C, but improvements were observed at higher temperatures. The wetting condition after spontaneous imbibition of seawater, seawater depleted in NaCl, and seawater depleted in NaCl spiked with sulfate was monitored using a chromatographic wettability test, and it showed an increasing order in the water–wet fraction, in line with increased oil recovery. The results were discussed in terms of the previously suggested mechanism and the effect of the ionic double layer at the rock–brine interface.

High data quality and improved environmental corrections of array induction logging tools have expanded their operating range into wells drilled with high-salinity water-based mud. Multi-laterolog tools are preferred for these borehole conditions when formation resistivity is high, but if the ratio of formation-to-mud resistivity is moderate, array induction tools can be used successfully. A fairly large region of formation resistivity and formation-to-mud resistivity contrasts exists where you would expect either array induction or multi-laterolog devices to perform well. However, each responds differently to borehole effects, near-borehole effects, and invasion. Data from both array induction and multi-laterolog devices was acquired in an offshore well from China with low-to-moderate formation resistivity drilled with high-salinity water-based mud. In some sections of the well the drilling assembly produced a "spiral" effect with small, periodic changes in borehole size. The majority of the well had no invasion but there was shallow conductive invasion in some permeable intervals. The differences in sensitivity to shallow conductive invasion and the significant effect of a very conductive "spiral" borehole on the array induction responses is illustrated and explained by modeling. A filtering technique to eliminate the spiral effect and improve the responses is described and illustrated. The multi-laterolog tool has no sensitivity to the spiral borehole shape. The determination as to whether an array induction or a multi-laterolog is the preferred resistivity device should be based on more than the value of formation resistivity or the contrast between mud and formation resistivity. In some conditions one has preference, while in other conditions it would be advisable to acquire both.

A solvent-based surface modification agent (SMA) has been very successful in precoating proppants to improve their performance in fracture stimulation treatments. To a far lesser degree, it was also used as an aggregating agent applied to formations and/or proppant packs to stabilize fines in a remedial method. However, its incompatibility with some aqueous wellbore fluids and the safety concerns due to the solvent base has limited its field applications. This paper presents the development of a new formulation of an SMA-aggregating agent that is aqueous-based, and includes results obtained from extensive laboratory studies. The new aqueous-based surface-modification agent (ASMA) provides significant improvements in health, safety, and ease of operation for the treatment of proppant, formation surfaces, and unconsolidated formations to control proppant and fines aggregation. Additionally, this ASMA will function to moderate undesirable diagenetic reactions that effect proppant strength, proppant pack permeability and formation permeability. A unique property of this ASMA is that the rate of release of the active SMA ingredient can be controlled allowing it to be used for primary fracturing treatments or as a remedial treatment of damaged proppant packs or inhibiting continued formation fines production. This means the ASMA can be added directly to frac fluid during a treatment to coat proppant, to a fracture stimulation treatment prepad to treat the formation face, or at a later time as a remedial treatment. As a remediation application, once injected into the proppant pack and formation matrix, the ASMA forms a thin film on the particulates, covering the fines and anchoring the particulates in place. In addition to controlling fines, ASMA coating forms a hydrophobic film that encapsulates the particulate surfaces, inhibiting the chemical reactions that lead to scale formation in the pack matrix and subsequent productivity loses. Experimental testing using packed beds of proppant, formation sands, and various fines were used to simulate proppant pack conditions and formation fines before and after remedial treatments. It was observed that only a very thin film was formed, which encapsulated the proppant or formation particulates and created cohesion between grains without plugging the pore spaces. Additionally, laboratory results show that ASMA treatments effectively mitigate the buildup of scale in various sand packs as well as successfully control the migration of formation fines into proppant packs to maintain fluid flow paths.

Summary Drilling activity has increased dramatically in unconventional shale gas reservoirs. The drilling fluid of choice in these shale plays is often nonaqueous-based fluid (NAF). While NAFs can provide advantages such as shale stabilization, lubricity, and contamination tolerance, environmental consequences and associated costs are an issue. These disadvantages cause operators to seek water-based muds (WBMs) for drilling many of these gas reservoirs. Despite some operational similarities, a wide variety of unique downhole conditions can be found in the shale plays. Shale mineralogy and bottomhole temperature (BHT) represent just two highly variable critical factors in unconventional gas reservoirs. Therefore, a single water-based solution for addressing shale plays globally is not a realistic option. Instead, a customized approach that delivers WBMs formulated specifically for a given shale play has been pursued. Customization relies on detailed analysis of the well parameters of a given shale play. This analysis includes not only the shale morphology and lithology but also well drilling program plans, environmental factors, and other reservoir-specific considerations. Applying appropriate drilling-fluid chemistries on the basis of this detailed analysis has led to the successful field deployment of a number of new shale fluids. Details of the process used for customizing a WBM for a shale play, as well as specific examples of new fluids developed for the Barnett, Fayetteville, and Haynesville shales, are presented in this paper. Full laboratory development and testing are described. Additionally, field-trial results are presented that show that specially designed WBMs can provide performance comparable to that of NAFs, but with enhanced environmental and economic benefits. Application of the customization process to develop WBMs for other shale plays around the globe is also discussed.

Hundreds of wells have been drilled since the early 1900's at the Putumayo basin in southwest Colombia. ECOPETROL (NOC) used traditional mud systems: lignosulphonates, potassium chloride, and finally lime or gypsum mud systems, all of them designed to manage exposure to anhydrite, a common mineral in the drilled formations. The calcium contamination adversely affects mud system properties, resulting in hole instability and frequent stuck pipe events. Because of these issues, the operator considered using oil base mud (OBM) in a very environmental sensitive area. The OBM would generate undesirable waste and there were uncertainties about its performance, since few wells in the area had been drilled with OBM and the results were not very successful. Therefore, for drilling operations on the ECOPETROL Sucumbíos No. 5 well, a completely new high performance water base mud (HPWBM) was proposed and accepted. The new chemistry eliminated the use of bentonite and included a new flocculation inhibition mechanism, as well as new and powerful polymers. The system demonstrated that calcium and anhydrite were not a problem any more and the well was drilled in record time. More importantly, to the operator was able to evaluate the productive formations by running electrical logs, an operation that was normally cancelled because of severe hole problems. Casings strings were set and cemented per the well program and the well was completed as planned. This paper presents the design state of the HPWBM, its performance while drilling and charts and graphics comparing the changes against the historical values recorded in the area.

Drilling offshore Abu Dhabi presents some unique challenges primarily related to wellbore instability in directionally drilled wells through the unstable Nahr Umr and Laffan shale formations. This not only affected drilling performance and cost millions of dollars due to non-productive time (NPT), but had also placed constraints on the Company’s field development plans, as it was not possible to drill high deviation wells through these shales with a high degree of success. It was a major challenge to develop and engineer a water-based drilling fluid that could effectively eliminate shale instability encountered while drilling these high deviation wells. The stabilization of these highly laminated shales required an effective synergistic blend of products to both maintain the chemical stability of the shales and minimize the transmission of fluid pressure into the shales, while sealing both natural and induced micro-fractures. The development of the ideal types and blend of products, treatments and engineering techniques tailored to these specific rock requirements is crucial to drilling success. The net result of the correct application of this unique drilling fluid system has been to mitigate the incidences of cuttings accretion, wellbore instability, time-related failure and induced losses into permeable formations, thereby eliminating drilling non-productive time. This paper describes the development and field application of a uniquely engineered water-based drilling fluid that demonstrates enhanced shale stabilization properties, much like the invert emulsion systems, but without the associated waste management equipment and logistics and environmental exposure. Additionally, the development and use of a new class of sealing additives is outlined showing how improved stabilization of the wellbore can be achieved while drilling these older, highly laminated shale formations. Extensive laboratory work was carried out under simulated conditions, on both the fluid system and sealing additives to optimize the fluid formulation. Thereafter, successful field applications were carried out in high inclination wells in the area. Drilling performances were greatly enhanced compared to conventional fluid systems, which accrued significant cost savings to the operator. Further, there is additional flexibility to drill high deviation wells through these shales, as required to reach a reservoir target. This development approach and the use of the unique stabilization additives can be utilized in many other areas where issues of wellbore instability in older and laminated or fractured shales exist.

Post-stimulation proppant-flowback problems have been a major issue in both conventional and unconventional reservoirs. In coalbed methane-gas (CBM) wells that use pumps and plungers to dewater coal, proppant flowback with produced fluid could lead to well downtime because the pumps can get sanded off. This is costly and challenges well economics because losing production and replacing the pumps repeatedly can be expensive. A low-cost solution to this uncontrolled sand production is to clean the well with a workover rig or coiled tubing (CT), identify the zone (or zones) from which the proppant is being produced, isolate the zone (or zones), and pump a remedial proppant flowback-control treatment. Two types of proppant-consolidation remedial-treatment fluids have been successfully used—one is the low-viscosity, solvent-based curable resin, and the other is a new, water-based consolidation system. A water-based consolidation system was successfully developed to overcome the operational, safety, and fluid-compatibility issues that most current solvent-based resins experience during field treatments. This paper presents the results of laboratory development and field testing of this consolidation system for proppant flowback. Extensive laboratory testing has indicated that an optimum concentration of coating is necessary to maximize the bonding between proppant grains. This allows the proppant pack to withstand high production flow rates and to overcome the effects of stress cycling while minimizing any reduction in its permeability. Field-study results in both sandstone and CBM reservoirs showed that the water-based consolidation system was successfully applied in treating proppant and formation solids in the near-wellbore region to lock them in place without damaging production flow paths. In these field tests, intervals in excess of 300 ft were treated effectively with the bullhead-squeeze method using consolidation treatment fluids that were foamed to a quality of 75% or higher to aid in diverting treatment fluids and extending treatment volumes. The new system uses small treatment volumes to impart excellent consolidation properties, while at the same time retaining formation permeability. This makes the treatment system simple to deploy and economically viable. In addition to providing the results, this work discusses the criteria for identifying remedial candidates, optimal placement procedures, and the lessons learned from these treatments.

A Gunung Kembang drilling campaign recently drilled three wells with 1,510-, 525-, and 283-ft MD horizontal section lengths. The landing point of these wells is 3,200 ft TVD in limestone formations. Failures from the first and third wells resulted from a total-loss circulation problem, and drilling was stopped following an uncontrolled loss rate and a diesel-oil stock shortage. Two suspected factors are believed to be the cause of loss circulation in Gunung Kembang: 1) depleted formation pressure, which recorded 6.8 ppg and led to a narrow margin of overbalance mud weight and minimum stability mud weight, and 2) the presence of natural fractures. This factor requires further discussion owing to the geomechanic study results, which predicted several azimuths that natural fractures will most likely encounter while drilling. Water-based mud then becomes an option for drilling a 6-in. horizontal section in the Baturaja limestone formation, as water supply is almost unlimited and is easy to acquire. A non-damaging fluid in combination with a glass-bubble lightweight additive is proposed for drilling this section to 1,600 ft MD. To minimize the possibility of loss circulation, mud density is designed to be slightly higher than the formation pressure. The formation pressure is recorded at 6.8 ppg, thus the mud weight will be 6.9–7.1 ppg (17–50-psi overbalance) using glass bubbles (hollow-glass spheres). A laboratory test regarding this mud system was conducted to determine the optimum concentration of glass bubbles in waterbased mud using the value of PV so as to affect ECD and surface circulating equipment reliability. A return permeability test was also conducted against the Baturaja limestone core sample with a 15% reduction in permeability. This result offers a better solution for the Gunung Kembang drilling campaign owing to its lower operational cost and that it is more environmental friendly.

In-situ heavy oil density and viscosity can vary laterally and vertically in carbonate reservoirs. The spatial distribution of these PVT properties must be determined accurately for reserve assessment, reservoir simulation, well placement and other field development processes. Although laboratory PVT analysis is the industry-standard source for fluid properties, the extensive time required to restore and process heavy oil fluid samples often minimizes the impact of such information during the drilling phase. The use of wireline formation testers, capable of measuring in-situ density and viscosity, can greatly aid the decision-making process providing timely basic PVT data, in addition to guiding the fluid sampling program and increasing the quality of the samples to be taken. While in-situ measurement of fluid density and viscosity in oil-based-mud is well-established, accurate determination of such properties can be quite challenging in water-based-mud environments; especially in those cases of water-dominated flow, strongly emulsified fluids or high fraction of sediments in the flow line. Several techniques, such as sampling point optimization, pressure and flow rate control during pump-out, and tool-string configuration can minimize the adverse effects, thereby improving measurement and sampling quality. Yet, there can still be cases where the measurement accuracy can be limited due to the specific combination of fluid and formation properties, and borehole conditions. In this paper, several case histories in a variety of borehole and mud conditions, including highly deviated and ultra-reach extended horizontal wells, are presented with comparisons to laboratory data when available. Results indicate that accurate in-situ density and viscosity determination is possible when sufficient amount of oil is present in the flow line. Experience also shows that measurement quality can be affected in suboptimal conditions involving strong emulsions, or range of viscosities outside the sensor specifications.

Use of high HCl concentrations to dissolve Mn3O4-based filter cake will result in corrosive environment and release of poisonous chlorine gas (i.e., strong oxidizer). Thus, removal of deposits formed at the wellbore because of drilling fluids becomes more challenging when dealing with additives (e.g., Mn3O4) that involve complex interactions with the cleaning fluids, especially at high temperatures. We studied the reaction of HCl with Mn3O4 particles as a function of time. Additionally, we investigated the release of chlorine gas up to reaction temperature of 284°F and 15 wt% HCl. Several techniques and instruments were employed in this study. Solubility of filter cake was examined using a HPHT filter press. GC/MS technique was used for chlorine gas analysis, atomic absorption were used to measure manganese concentrations, and to analyze solids remained after reaction we used x-ray diffraction. Solubility of filter cake using 10 wt% HCl and temperature of 250°F was 78 wt% (no mixing during the reaction). At 190°F, high concentration of HCl (10 wt%) showed complete solubility of Mn3O4 particles while, 1 and 4 wt% HCl showed ∼70 wt% solubility. Chlorine gas was not dissociated using 4 wt% HCl at 190°F. At 284°F, 5 wt% HCl was enough to release chlorine gas. Therefore, HCl concentrations lower than 5 wt% are recommended and will dissolve most of Mn3O4. The following reaction agrees with the experimental results of 1 and 4 wt% HCl at 190°F: Mn3O4+4HCl⇌2MnCl2+MnO2+2H2O

Design of drilling fluids is crucial to extended reach drilling (ERD) with the challenges including borehole stability, hole cleaning, lubricity and equivalent circulating density (ECD) management. Normally, oil-based drilling fluids would be the best choice for an extended reach well with a horizontal displacement of 8000m. However, the Liuhua Oilfield is located in the South China Sea, an environmentally sensitive area. It is necessary to develop the high performance water-based drilling fluids which offer the performance to match oil-based drilling fluids.The integrated design proposal of water-based drilling fluids for the well Liuhua 11-1-B3 ERW4 with a horizontal displacement of 8000m (26247ft) is discussed in this paper, including design criteria, the formulations and the parameters of performance of the drilling fluids in each interval of the well. The more attention is paid to the 12 1/4-in. open hole section, where a kind of high performance water-based mud (HPWBM) is prepared. The two newly developed chemical additives, an amine polymer and an aluminum complex, are added in the KCl/polymer drilling fluid which was successfully used in the extended reach wells with a horizontal displacement of 6000m in this oilfield. In addition, a membrane-forming agent is added in this mud system and an optimized combination of lubricants was used to improve the lubricity of the drilling fluid.Numerous experiments were conducted to evaluate the various properties of this novel water-based drilling fluid. The experimental results indicate that it has excellent rheological properties, very low filtration rate, good lubricity and strongly inhibitive character to shale, which are very close to the commonly used oil-based drilling fluids.The results of risk analysis show that the design proposal of this water-based drilling fluid is feasible and can meet the drilling requirements of ERD with a horizontal displacement of 8000m open hole section in this area with less pollution of the sea and without increasing more cost.

This paper reviews recent developments in enhanced oil recovery (EOR) techniques published in SPE conference proceedings for 2007 to 2009. It also updates the EOR criteria developed by Taber et al. in 1996 based on field applications reported in Oil & Gas Journal and at various SPE conferences. It classifies EOR methods into five main categories: gas-based, water-based, thermal, others, and combination technologies. New developments in EOR techniques, chemicals, and mechanisms are summarized to clarify advances in EOR criteria beyond previous limitations. Reservoirs that had previously been ruled out based on specific reservoir conditions are now candidates under updated EOR screening criteria. To demonstrate this potential, this work has established guidelines for the selection and optimization of chemical EOR methods for a specific reservoir.

A novel fracturing fluid called VAS (anionic surfactant type) has been successfully developed and applied in both oil and gas wells in China. VAS can not only minimize matrix damage caused by modifying the rock surface charge and lowering watersensitive and water-lock. This paper presents the stimulation mechanisms of the novel VAS fracturing fluid. Field demonstrations indicate that, for the wells using the VAS fracturing fluid, the production increased remarkably and stabilized longer than the wells using water-based Guar gum fracturing fluid. Averagely, the production for the wells using this VAS fracturing fluid increased by 120% compared with the wells using acidic fracturing fluid and increased by 89% compared with the wells using ethyloic fracturing fluid.

In the case of deviated, horizontal, extended reach and multi-lateral wells, the existence of a particle bed and also the formation of a partially or completely buried cuttings bed can be problematic for borehole cleaning. As a solution increasing the drilling fluid velocity can help in eroding the deposited bed substantially above a critical velocity, which depends on several flow parameters. For instance pipe rotational speed can enhance particle transportation at flow velocities lower than the critical annular fluid velocities as reported in the literature. The consequences of pipe rotation on the fluid transport ability are also subject to the inclination of the drilled section. The present paper discusses the results of numerical simulations of water based drilling fluid flows regarding the inclination effect, the fluid viscosity, the clearance between the pipe and the borehole and the resulting pressure losses.

Oil-based fluids (invert emulsion fluids) have for many years been the fluid of choice for use in challenging hole sections. These fluid systems can bring many advantages, including optimal shale stability, low torque and drag, good resistance to contamination, and high drilling rates. One of the challenges of utilizing an invert emulsion fluid, however, has been the increasing level of environmental concern and legislation associated with its use. These challenges have driven the search for a high performance water-based fluid that will provide oil-based fluid performance and be environmentally acceptable in all offshore areas of the Egyptian Mediterranean Sea. A novel, environmentally compliant high performance water-based fluid (HPWBF) system has been developed that has proven to be extremely inhibitive and highly lubricious. Use of this new HPWBF system has helped operators to drill some of the most reactive shales in the Egyptian Mediterranean Sea while avoiding the high cost and safety risks associated with "skip and ship" operations. This performance is coupled with excellent cuttings integrity, increased temperature stability and good hole-cleaning properties. In the application of this system, the engineered approach matches fluid requirements with local clay characteristics, environmental regulations and operational objectives. A HPWBF was chosen to drill Petrobel's well Karam-1 with a great success. The fluid was utilized to drill 334 meters of 12¼" hole section through the very challenging highly reactive formation of Kafr El-Sheikh stratum. The following conditions existed for this operation: Fluid must be water-based to meet environmental stipulationsThe shale section would be exposed for up to 10 days while loggingBottomhole temperature is 230°FApproximately 100 m 17½" rat hole existed below the 13 3/8" casing This paper discusses the technical challenges and highlights the criteria for the proposed fluid system and the successes achieved in this well.

The detailed laboratory studies have been carried out with the aim at restricting the spontaneous imbibition and penetration of drilling fluids in tight sand gas and BCGA reservoirs. The measurements were extended to natural cores having permeability between 1 and 0.001 mD. It was found that because of the unusual pore structure and water-wet character of the cores extremely high capillary forces predominantly determine the flow and spontaneous imbibition phenomena in natural cores obtained from unconventional gas reservoirs. Based on the experimental results, it was clearly indicated that the water is a natural blocking phase, causing serious formation damaging hard to cure. Consequently, the fluid penetration from drilling fluids can be modified only by surface (interfacial) tension lowering and wettability alteration (from strongly water-wet to intermediate or oil-wet state). In addition, proper selection the cake forming components may significantly decrease the liquid uptake in tight, low permeable sandstones. The laboratory studies proved that using special surfactants, organic water miscible solvents and special high molecular weight additives the spontaneous imbibition and penetration of liquid phase of the water-based drilling mud can significantly be influenced in unconventional gas reservoirs mitigating thus the formation damage often encountered in tight sands and BCGA.

Efficient removal of cuttings from the wellbore is one of the major considerations during a successful drilling operation. Fluid velocity is known to be the most dominating drilling parameter on hole cleaning. If the fluid velocity is lower than a critical value, a stationary bed develops, which leads to problems like pipe stuck, high torque-drag, increase in bottomhole pressure, increase in hydraulic horsepower requirements, etc. During a drilling operation, besides the fluid flow and presence of cuttings, there is pipe rotation. Determining the pressure losses in such a complex system is very difficult. This study aims to estimate the frictional pressure losses in horizontal and highly inclined wells considering pipe rotation and presence of cuttings. Extensive cuttings transport experiments have been conducted on METU Cuttings Transport Flow Loop using pure water as well as numerous water- based muds consist of different concentrations of xanthan biopolimer, starch, KCl and soda ash, weighted with barite for various inclinations, flow rates, rate of penetrations and pipe rotation speeds. Pressure drop within the test section, and stationary and/or moving bed thickness are recorded besides the other test conditions. Observations showed that, pipe rotation has a significant influence on decreasing critical velocity required to prevent stationary bed development, especially if the pipe is making an orbital motion. However, after a certain pipe rotation speed, no additional contribution of pipe rotation is observed on critical velocity. Moreover, a reduction in the pressure drop is also observed due to the bed erosion while rotating the pipe, when compared with no pipe rotation case under the similar drilling conditions. Empirical correlations are developed based on the experimental data for estimating pressure drop. It is observed that the results obtained from the correlations are reasonably accurate, within an error range of 10% for estimating pressure drop, when compared with the experimental observations.