Water-based Mud Systems Research Articles

High Performance Water-based Drilling Fluids—A High Efficiency Muds Achieving Superior Shale Stability While Drilling Deepwater Well with HPHT in South China Sea

In deepwater drilling operation, low temperature, high pressure, gas hydrate, narrow density window are the major challenges for drilling fluids to meet, and with the increasing depth drilled, high temperature and high pressure condition was occurred in deepwater well. In the other side, Oil based muds (OBM) and synthetic based muds (SBM) are limited in using because of the strict environment rules in the South China Sea. In deepwater HTHP well, shale hydration, dispersion and Equivalent Circulation Density (ECD) caused by rheology change with high temperature difference are the two critical problems. Therefore, petroleum service institutes and companies take much time and money on research to develop a high performance water-based mud system (HPWBM) to solve these problems and improve drilling efficiency. In the paper, a new method to estimate amine derivatives was proposed, the specific test steps was introduced in detail, and secondly a High efficiency muds (HEM) are selected and the main properties were evaluated in lab such as rheological properties at lower temperature, shale inhibition and anti-accretion. Finally, the system was applied successfully in LS project in the South China Sea. The results showed that HEM system delivered high drilling performance such as shale stability, high pressure and high temperature (HPHT) resistance, lubricity and high rate of penetration (ROP) with no wellbore problems, and the system is suitable for deepwater HTHP well operation.

High-Temperature Water-Based Mud Faces Challenges Offshore Sarawak, Malaysia

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 28484, “Learnings From the High-Temperature Water-Based-Mud Application in Offshore Sarawak,” by M. Abshar M. Nor, SPE, M. Solehuddin A. Razak, and Lingges Devadass, Petronas, prepared for the 2018 Offshore Technology Conference Asia, Kuala Lumpur, 20–23 March. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission. The reservoir section of a gas field offshore Sarawak, Malaysia, consists of two massive pinnacle carbonate structures with heterogeneous porosity and permeability and many vugs and faults. Severe to total loss of circulation was expected along with a high bottomhole temperature (BHT). Considering the high risk of lost circulation, the drilling-fluid strategy involved designing and testing a high-temperature (HT) -tolerant water-based mud (WBM). While the main hole was drilled successfully with the HT WBM, the sidetrack experienced a significant reduction in rate of penetration (ROP). Well Design and Execution Challenges During the design stage, determination of the severity of losses in the carbonate formation was met with high uncertainty. Consequently, a WBM system was selected to drill the 8½-in. reservoir section. A shale formation was predicted to be above the carbonate section, and a 95/8-in. casing was planned to be set as close as possible at the top of the carbonate to isolate the shale. With the 95/8-in. casing in place, the WBM was to be used to drill the shoe track and the remaining small shale section before entering the carbonate reservoir. The BHT of the reservoir was predicted to be 370°F, which was extrapolated from data from offset wells. In addition, the pore pressure in the reservoir was overpressured approximately 14 lbm/gal because of a gas column in the carbonate. The high BHT coupled with the high mud-weight requirement of up to 14.5 lbm/gal led to the design of an unconventional HT WBM, which was a first for the operator. Special attention also was given to the corrosion risk on the drillstring from expected hydrogen sulfide levels up to 150 ppm and carbon dioxide levels up to 20% in the reservoir. Predrill Laboratory Study Laboratory tests were conducted to address major well challenges and overall performance of the system under extreme borehole temperatures. To ensure the mud system was able to withstand temperatures up to 400°F, a synthetic polymer was introduced to the mud design. Several mud formulations were tested and fine-tuned to achieve well-specific mud specifications for optimal hydraulic capability. Laboratory tests in accordance with American Petroleum Institute Recommended Practice 13B were conducted to evaluate the mud properties with various concentrations of additives. Four samples—Samples A, B, C, and D—were prepared and submitted to the same test procedure to understand the mud rheological behavior upon exposure to the HT environment.

Evaluating the Effects of Monovalent and Divalent Salts on the Rheological Properties of Water Based Mud

Introduction:Drilling fluid selection plays a key role in preventing major problems encountered during drilling operations such as hole pack-off, stuck pipe and loss circulation. Mud contamination which results from the overtreatment of the mud system with additives or foreign material entering the mud system during drilling operations causes unwanted changes in the properties of the mud. This makes the mud system inefficient in performing its major roles. This research studies the effects of monovalent and divalent salts namely Potassium Chloride, Calcium Chloride, and Magnesium Chloride on the rheological properties of water-based mud system which is most vulnerable to contamination.Methods:Sixteen mud samples were formulated of which fifteen were contaminated each with different concentrations (0.75 g, 1.50 g, 2.50 g, 3.50 g, and 5.0 g) of the various salts at ambient temperature.Results:The results showed that the rheological properties such as plastic viscosity, apparent viscosity and yield point of the mud samples decreased as the concentrations of various salts increase.Conclusion:It was concluded that increase in the concentration of the salts resulted in a decrease in the rheological properties of the mud samples. This indicates that with the monovalent and divalent salt contamination, there is a significant decline in the performance of drilling mud since the salts affect the dispersion, hydration and flocculation behaviour of the particles. The effect was more profound with CaCl2 and MgCl2 salts than the KCl salt.

Experimental investigation of rheological and filtration properties of water-based drilling fluids in presence of various nanoparticles

For the past decades, considerable attention has been focused on the manufacture of a high-performance, environmentally compliant water-based mud system to be a better choice than oil and synthetic-based muds (OBM/SBM). However, the improvement of WBMs has not reached the satisfactory level yet and attempts in this regard should be continued. Accordingly, in this study, an attempt was made to improve the performance of a Bentonite-WBM by adding four types of hydrophilic nanoparticles (NPs), namely aluminum oxide (Al2O3), titanium dioxide (TiO2), silicon dioxide (SiO2), and copper oxide (CuO). The NPs were dispersed in the drilling fluid with concentrations of 0.01, 0.05, 0.1 and 1 wt%. The results revealed that the Al2O3 NPs increased the amount of mud filtration up to 80% while the mud cake quality became poorer as compared to the based mud. In contrast, the amount of mud filtration had a decreasing trend when SiO2, TiO2 and CuO NPs were applied especially at the concentration below 0.5 wt%. Rheological properties and gel strength were also improved in the presence of TiO2, Al2O3 and CuO NPs in comparison with the based mud. Overall, it was concluded that adding of the NPs at concentrations below 0.5 wt% to the Bentonite-WBM has potential to improve rheological and filtration properties.

Optimizing aqueous drilling mud system viscosity with green additives

Non-governmental and governmental agencies are demanding for environmentally friendly mud systems. This increase in environmental awareness has made the drilling mud service companies to re-evaluate some of the chemicals and materials used as additives for mud systems. In this study, some green materials were considered as possible substitutes for PAC R in water-based drilling fluid systems. The rheological properties of four water-based mud systems with typical compositions were studied at 80 and 150 °F. These two temperature ranges were necessary so as to evaluate the effect of temperature on the viscosity, plastic viscosity and yield point properties of these mud systems formulated with these green materials as viscosifier. These green materials were processed to powder form and sieved to their finest particle sizes to reduce amount of solute that will be present in the water-based drilling fluid formed with the materials. The properties of the formulated mud systems were analyzed using API standard. These green materials behaved optimally as viscosifiers for the formulated water-based mud systems under ambient temperature. Also the mud systems behaviour at 150 °F showed a reduction in the flow properties at this high temperature as recorded in the literatures. From the results of the experiment, we can say that Kian (Averrhoa carambola L.) has the characteristic of being a substitute for PAC R when beneficiated for water-based drilling fluids.

Development of an Environmentally-Friendly Water-Based Mud System Using Natural Materials

Drilling muds are complex formulations of a range of chemicals designed to have specific properties under very specific drilling conditions. Environmentalists including different government and non-government agencies always have a concern regarding the conventional drilling mud system because drilling industry has no choice but to use huge amounts of chemicals as additives. These chemicals are toxic and pose an excessive threat to mankind as well as the environment. The recent priority of any drilling program considers the development of environmentally-friendly drilling fluids so that the ecology is preserved to its maximum level. This article proposes three naturally occurring materials—date seeds, powdered grass, and grass ash as possible additives in the drilling mud system. Sieve analysis and laser particle size analysis are conducted to study the particle size of the three materials. SEM–EDX analysis is performed to know the elemental composition of the proposed additives. Experimental tests on rheology and filtration are conducted at room temperature on the proposed materials to determine the applicability of these natural substitutes as drilling fluid additives. Results show that date seeds, grass, and grass ash can be used as a rheology modifier, and a filtration control agent to formulate the water-based mud system.

Experimental Analysis of the Effect of Fine Milled Husk of Rice as a Novel Filtration Control Agent for Water Based Drilling Fluid System

Drilling operation is a complex process that requires integration of various engineering systems. As the drilling continues, the formation encountered offers challenges to wellbore integrity as pressure increases with depth. The influx of formation fluid is contained by the overbalance provided by weighted drilling fluid column. Another critical function of the mud is to restrict the filtration fluid lost to the formation by forming a suitable mud-cake around the wellbore. Drilling fluids are designed to reduce filtration loss by addition of filtration control agents. This paper is a comprehensive study of the effects of fine milled Husk of Rice as a filtration control agent in water based mud system by experiments performed at laboratory conditions. Filter Loss and Rheological properties of the mud were studied by changing the concentration of the Husk of Rice in water based mud system. Keywords: Drilling Fluid, Mud, Fluid Loss, Mud Cake, Husk of Rice

Formulation of a water based drilling fluid system with synthesized graft copolymer for troublesome shale formations

Shale formations consisting of reactive clay mineral of smectite group like montmorillonite may lead to severe wellbore instability problems with conventional water based drilling fluids. This may be due to their high magnitude of rock-fluid interaction inside the wellbore. Problems like hole enlargement, pipe sticking, high toque and drag etc. may escalate drilling cost and time. The present study deals with the applicability of synthesized polyacrylamide/dially dimethyl ammonium chloride-grafted-gum acacia copolymer in formulation of novel water based drilling mud system (WBDMS) for troublesome shale formations. The mechanism behind the synthesis was free radical polymerization. The structural information and morphological properties of copolymer were determined by Fourier transform infrared spectroscopy (FTIR) and Field emission scanning electron microscopy (FESEM). Further, its effect on filtration and rheology of developed mud system was analyzed thoroughly as per API standard procedures. Further, effectiveness of graft copolymer on the shale stabilization was investigated using shale dispersion and slake durability tests. The reactivity of core sample with the developed drilling fluid system was analyzed using core flooding experimental setup. The experimental investigations showed that synthesized graft copolymer has significant effect on rheological parameters and filtration characteristics of the system due to its synergistic effects in the developed system. Also, its shale stabilization property was superior to the commercially used shale stabilizer (partially hydrolyzed polyacrylamide polymer). It was evident from the high values of shale recovery and slake durability index. This was achieved due to the presence of cationic ions and formation of a protective coating on shale cuttings. It has also resulted in the low magnitude of rock-fluid interaction. The developed drilling fluid system exhibited low reactivity with the core sample during core flow studies. Thus, the synthesized graft copolymer can be utilized as an additive in the formulation of water based mud system customized for reactive shale formations.

The evaluation of borehole imaging result comparing with cores in Sarvak fractured and non-fractured reservoir

Core samples are still today considered as the standard measurement against all other measurements which must be compared. Core analysis usually focuses on the worse portion of the reservoir due to the fact that core recovery has rarely been well in a highly fractured zone; hence, permeability measured from core sample is often not representative. Core analysis is a common method to identify small-scale fractures of the well and permeability and porosity; however, there are some limitations in the core procedure such as it is highly expensive and unidirectional and has a low recovery coefficient in fractured zone. In contrast, there tends to be a mistrust and even a suspicion of those logging instruments that make measurements which threaten to replicate or even replace the “sacred core.” Thus, image logs are more useful to study the subsurface fractures in these such cases and the logs which come closest to achieving this are the high-resolution micro resistivity (OBMI) and acoustic geological imaging (UBI). The core and OBMI-UBI result was matched in order to verify the log measurements. Furthermore, FMI data were integrated with other open-hole logs to derive a permeability curve. As demonstrated in the case studies, it is believed that the permeability in the basement could be reasonably evaluated using this method. As a result, this exercise has proven to be very valuable, not only for demonstrating the value of the log data, but also it has also highlighted some significant limitations of the core in water-based mud and oil-based mud systems.

Experimental Investigations Into the Performance of a Flat-Rheology Water-Based Drilling Fluid

Summary The aqueous drilling fluid (AF) with unique flat rheology (FR), as a potential alternative to nonaqueous fluids (NAFs), is meaningful in deepwater operations. In this work, a novel FR water-based mud (WBM) was presented. An evaluation of FR profiles was conducted on the designed system by detecting the typical rheological data at a certain temperature and pressure range. The results showed that for the newly developed WBM, in addition to typical FR parameters [i.e., 6- and 3- rev/min readings and yield points (YPs)], the viscosity term also delivers near-constant variations in the temperature range of 39 to 150°F. To attain FR profiles, the rheological modifier appears to be necessary for its temperature-activated behavior. In addition, the FR WBM displays lower pressure and temperature dependence. The laboratory contamination tests indicated that the WBM system possesses excellent inhibition and lubricity properties as well as a strong tolerance to the contamination of seawater and sand/mudstone cuttings.

Vegetation Response to a One-Time Spent Drilling Mud Application to Semiarid, Mixed-Grass Prairie

Landspraying while drilling (LWD) is an approved disposal method for water-based drilling mud (WBM) systems in western Canada. The mud is applied either on cultivated land, where it is incorporated by cultivation, or on vegetated land where it is not incorporated. This study examined the effects of summer WBM application (0, 15, 20, 40, and 80 m3 · ha−1) on native vegetation properties. Our results indicated that LWD increased bare ground but decreased lichen cover at the 80 m3 · ha−1 rate relative to the untreated control. Nitrogen (N), sulfur (S), and magnesium (Mg) concentrations in aboveground plant tissue increased with increasing LWD rate in samples taken 45 d after WBM application, but these differences disappeared 1 yr after treatment. Increase in tissue concentration of phosphorus (P) with LWD rate, however, was only detected 3 yr after LWD. Nonetheless, these changes in tissue chemistry were not associated with significant changes in biomass yield or species composition. Overall, our results suggest that single WBM applications at rates (≤ 20 m3 · ha−1) commonly used in western Canada, if properly managed, are unlikely to adversely affect native prairie vegetation. El rociado del terreno durante la perforación (LWD) es un sistema aprobado de eliminación de lodo en sistemas de perforación basados en el uso de agua (WBM) en el oeste de Canadá. El lodo puede aplicarse a tierras arables, donde es incorporado al suelo mediante la labranza, o a tierras con cobertura de vegetación donde no es incorporada al suelo. Este estudio examinó el efecto de la aplicación de WBM durante el verano (0, 15, 20, 40, y 80 m3 · ha−1) sobre las propiedades de la vegetación nativa de la pradera. Nuestros resultados indicaron que el LWD incrementó el suelo desnudo pero provocó una disminución en la cobertura de líquenes comparado con el testigo cuando la aplicación fue de 80 m3 · ha−1. La concentración de nitrógeno (N), azufre (S), y magnesio (Mg) en los tejidos vegetales aéreos aumentó con incrementos en la dosis de LWD en muestras tomadas 45 días luego de la aplicación del WBM, pero estas diferencias desaparecieron un año después del tratamiento. El aumento en la concentración de fósforo (P), sin embargo, sólo se detectó tres años después del LWD. No obstante, estos cambios en la composición química de los tejidos no estuvieron asociados a cambios significativos en la producción de biomasa o en la composición de especies. Nuestros resultados sugieren que en general, una única aplicación de WBM en dosis (≤ 20 m3 · ha−1) comúnmente usadas en el oeste de Canadá, no tendría un efecto negativo sobre la vegetación de la pradera si la misma es manejada correctamente.

Rheological properties of biopolymers drilling fluids

Drilling muds are complex fluids, generally used to clean the well, maintain hole integrity, transport the rock cuttings, lubricate the drill bit and control formation pressures. Two basic types of drilling fluids are used, water based muds (WBM) and oil based muds (OBM). OBM are very effective but polluting, and environmental regulations continue to restrict the use of oil based muds in many areas of the world. In order to reduce the mud toxicity, we developed water based mud systems using two biopolymers, which are xanthan gum and scleroglucan, generally proposed for high permeability reservoirs or for complex geometries such as horizontal wells. In this study, we evaluated the rheological behaviour of different samples and we determined the effect of components such as clay, calcium carbonate and potassium chloride. This formulations exhibit non-Newtonian rheological behaviour which can be described well by the tree parameter in Herschel–Bulkley rheological model.

New Water-Based Mud Balances High-Performance Drilling and Environmental Compliance

SummaryA new water-based mud system was successfully introduced as a high-performance, environmentally compliant alternative to oil and synthetic emulsion-based muds (OBM/SBM). Historically, emulsion muds have been the systems of choice when drilling challenging onshore, continental shelf, and deepwater wells to minimize risk, maximize drilling performance, and reduce costs. However, environmental constraints, a high frequency of lost circulation, and the high unit cost of emulsion systems sometimes negate the benefits of their use. Conventional water-based muds (WBM) offer the benefits of environmental compliance, attractive logistics, and a relatively low unit cost but consistently fail to approach the drilling performance of OBM and SBM.The new high-performance, water-based mud (HPWBM) is designed to close the significant drilling performance gap between conventional WBM and emulsion-based mud systems. The system has undergone extensive field testing on very challenging onshore, deepwater, and continental shelf wells that would otherwise have been drilled with oil or synthetic-based muds. This paper provides a detailed, technical overview of the new system, discusses its inherent environmental advantages, and presents case histories comparing performance to offset wells drilled with emulsion and conventional WBM systems.

Brine Imbibition Damage in the Alpine/Colville River Field, Alaska

Abstract Early exploration well tests in the Colville River Field (also known as Alpine) drilled with water-based mud systems exhibited unexplainably high near wellbore residual skin damage as documented by pressure build-up testing. Typical formation damage echanisms including clay reactions, mechanical damage, and gas trapping could not explain the damage. Between March 1998 and July 2001, laboratory testing determined imbibition-induced water trapping to be the primary formation damage mechanism. In situ water saturation is significantly lower than the residual or connate water saturation, a condition rarely encountered in the field. Lab tests quantified impacts and identified methods to minimize or eliminate formationdamage. This paper documents how successful identification of a unique damage mechanism improved drilling results in a low permeability sandstone. Introduction Exploration drilling results in Colville River prospects consistently demonstrated higher than expected near wellbore skin damage as measured by build-up test analysis. Investigations into more common damage mechanisms such as solids migration and clay swelling could not explain the damage. Early reservoir core studies indicated that residual water saturations from relative permeability curves should be higher than the observed initial water saturations. Later studies with traced core confirmed initial water saturations were considerably less than normal connate water saturations. Further lab work confirmed the water-blocking tendency by measuring water imbibition and permeability recovery during regain permeability tests. Various drilling fluids were tested, with oil-muds consistently delivering lower permeability losses than water-based fluids. For a number of operational reasons, all wells on the first development pad (CD1) were drilled with brine-based fluids. The second pad (CD2) development team accepted the lab results and, after demonstrating the potential benefits of oil-based mud drilling, convinced the drilling team to develop and test a suitable mud program. Initial test results confirmed the lab results and conclusions when Well CD2–47 came in flowing at 300% more than predicted, based on equivalent brine-based mud completions in comparable pay to date. Following this early success, the oil-mud program was expanded and has consistently delivered more productive wells in line with expectations from the lab work. Background The Colville River Field (also known as the Alpine Field) is located approximately 100 km due west of the Prudhoe Bay Field on the north slope of Alaska (see Figure 1)(1, 2). It contains 70 × 106 m3 of recoverable reserves, with approximately 160 x?106 m3 of oil-inplace. Production is from the Alpine Oil Pool, a very fine-grained Jurassic age shallow marine sandstone complex with stratigraphically trapped 40 °API oil. The reservoir is normally pressured and undersaturated. Initial reservoir pressure is approximately 5,500 kPa above the bubble point, and the primary recovery mechanism is solution drive. Figure 2 presents a log and petrophysical overview, and Table 1 provides a summary of key reservoir properties. The field was discovered in 1994 with the drilling of the Bergschrund No. 1. Further delineation confirmed the prospect during subsequent winter seasons, and gravel pad construction began during the 1998 winter season.

Understanding Torque and Drag: Best Practices and Lessons Learned From Captain Field Extended-Reach Wells

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 91854, "Understanding Torque and Drag: Best Practices and Lessons Learned From the Captain Field Extended-Reach Wells," by G. Rae, SPE, Chevron Upstream Europe, and W.G. Lesso Jr., SPE, and M. Sapijanskas, Schlumberger, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February. Torque and drag (T/D) analysis was used for successful extended-reach drilling (ERD) in the Captain field in the North Sea. The tactics used in overcoming issues such as drill length and the associated risk are explained. The applicability of available T/D-reduction technologies and why many of them were eliminated as possible solutions reinforced the criticality of good T/D analysis on this project. Introduction The Captain field is in the U.K. sector of the North Sea, approximately 81 miles northeast of Aberdeen, in a water depth of 369 ft. Because of the high viscosity and low temperature of Captain oil, long horizontal wells are required to drain the reservoirs effectively (Fig. 1). Although the field was discovered in 1977, it was not until 1995 that appropriate technology was available and development approval was received. The field was developed as a phased installation with two drilling centers tied back to a central floating production, storage, and offloading vessel. Before starting the Captain subsea development, 29 directional wells were drilled in the first, or Area A, development of the Captain field. The requirements of the subsea, or Area B, development were demanding. These were factored into the rig selection and subsequent drilling specification. The Captain sands are shallow, at approximately 3,000 ft true vertical depth (TVD), and soft. The reservoir is thin but prolific. Geosteering or precise directional control in horizontal sections was necessary. The completion design required a 250-ft straight section (dogleg severity less than 1.0°/100 ft) no more than 350 ft TVD above the reservoir. This section is where the submersible pump would be placed. The design also dictated that the directional build rate shallower than this pump tangent be less than 4.5°/100 ft. The wells would be drilled with water-based mud (WBM) for environmental considerations. A WBM system also was necessary in the horizontal sections to achieve inflow-performance requirements.

Brine Imbibition Damage in the Colville River Field, Alaska

Summary Early exploration well tests in the Colville River field (also known as the Alpine reservoir) drilled with water-based mud (WBM) systems exhibited unexplainably high near-wellbore residual skin damage documented by pressure-buildup testing. Typical formation-damage mechanisms, including clay reactions, mechanical damage, and gas trapping, could not explain the damage. Between March 1998 and July 2001, laboratory testing determined imbibition-induced water trapping to be the primary formation-damage mechanism. In-situ water saturation is significantly lower than residual or connate-water saturation, a condition rarely encountered in the field. Lab tests quantified impacts and identified methods to minimize or eliminate formation damage. This paper documents how successful identification of a unique damage mechanism improved drilling results in low-permeability sandstone.

Successfully Replacing Oil-Based Drilling Fluids With Water-Based Drilling Fluids: Case Study Demonstrates Value of Extensive Planning and Execution in an Extended-Reach Well

Summary An extended-reach well was planned and successfully drilled with a water-based drilling fluid in an area where wells historically have been drilled with mineral oil- and ester-based drilling fluids—the North Sea central Graben. The high cost of cuttings drilled with inverts that must be shipped to shore for processing and disposal coupled with the potential shutdown of drilling operations in times of bad weather (when cuttings could not be transferred from the rig to supply vessels) led the operator to revisit the use of water-based drilling fluids, especially in the large-diameter hole section in which large amounts of cuttings are generated. However, many water-based systems have been used in the central Graben with little success. The need to develop a stable, shale-inhibiting, waterbased mud (WBM) system capable of performing well in extended-reach drilling (ERD) applications was identified. Extensive prewell modeling of wellbore stability in problematic shale zones and of hole cleaning in the large-diameter interval contributed to the success of this challenging project. This article discusses the planning, preparation, and successful drilling of the intermediate interval with a water-based drilling fluid.

Real-Time Specific Energy Monitoring Enhances the Understanding of When To Pull Worn PDC Bits

Summary Knowing when to change dulled bits can significantly reduce costs, which can be particularly important in high-cost environments. However, current techniques are based more on speculation and hope rather than science. The concept developed to dramatically improve this inefficient decision process involved measuring the mechanical energy input at the drill rig floor, calculating the drilling specific energy (SE), checking the current formation type with real-time downhole gamma ray (GR) readings, comparing the SE with the benchmark new-bit SE, and then using these values to assess the bit's "dull" state. This method has been proven to work in synthetic-based mud systems in which balling does not mask the bit's dull condition. It was imperative that the operator proved that this process worked in water-based drilling fluids that had replaced earlier synthetic muds because of environmental concerns, cost, and improved performance in water-based mud (WBM). Recently, the operator established that this process worked in water-based mud systems treated with antiballing chemicals. The case studies in which this methodology was developed are presented and discussed.

日本におけるここ１０年間の掘削泥水の技術革新と今後の課題

There are three technical innovations related to drilling fluids technology in this decade in Japan.Two of them are developments of the ultra high temperature water-based mud system and the extremely high lubricity water-based mud system. These two water-based mud systems had given big contribution to the drilling of ultra-deep high temperature, high pressure wells and horizontal, extended reach wells.Third innovation is the development of new waste mud disposal treatment system with using distillation technology. Much waste volume could be reduced by this new treatment system in oil field.Developments and actual field trials of these three new innovated systems are described in this paper, and also further break-through related to drilling fluid is described.

An Experimental Study of the Swelling Behaviour of Mudrocks In the Presence of Water-based Mud Systems

Abstract Swelling behaviour of three different mudrocks (London Clay, Oxford Clay and Fuller's Earth) of varying composition, geological ages, degree of lithification, organic matter and. expandable clay contents have been investigated in the presence of water-based mud systems (KCIICMC, Polyamine, Polyamine, + glycol and PHPA + glycol) plus water to identify the factors controlling the swelling behaviour of shales. The results show, that the degree of swelling is not directly correlatable with the proportion of swelling clay minerals in the mudrocks. Based on the experimental results, the swelling behaviour of the mudrocks depends on the composition, geological history and degree of, lithification of the mudrocks. Well lithified smectite-rich mudrock was found to show less swelling than less well lithified mudrocks with lesser amounts of swelling clays. Organic matter rich mudrock showed a greater degree of swelling than those with little organic matter, suggesting that organic matter may also influence the swelling behaviour. This investigation pro' vi des a better understanding of the swelling behaviour of mudrocks by introducing the concept of the combined action of physico-chemical and mechanical swelling processes. Introduction Swelling behaviour of different rock-fluid combinations is very important in predicting different drilling problems and determining the proper mud system to stabilize the troublesome shaley borehole environment. This characteristic of rocks is a complex function of the rock type and the mud systems and is one of the main causes of sloughing, heaving, caving and progressive hole enlargement problems in the shaley section of a borehole environment, 3). Swelling causes easy detachment of clays or shale particles both from the borehole wall and the cuttings, incorporating into the mud system as additional solid materials, and thus produces considerable changes in the rheological properties of the mud, increasing risk of differential sticking, induced fracturing and mud treatment cost. It is widely believed that smectite clay content of the mudrocks is the main culprit for excessive swelling of shale materials. In the context of drilling, this criterion of shale swelling is often unable to explain the unusual swelling behaviour of some mudrocks having little or no swelling clays. On the other hand it was found that some smectite' rich shale formations(2) have very little swelling potential compared to shales having low expandable clay content. his illustrates the role of other factors in controlling the swelling behaviour of mudrocks. Bearing this in mind an investigation was carried out to determine the factors governing the swelling behaviour of mudrocks. TABLE 1: Composition of the clay fraction <2 micron) and TOC of the mudrocks. Three different mudrocks and four different drilling mud systems plus fresh water were used for the study. The mudrocks are London Clay representing the Upper Tertiary mudrock, Oxford Clay representing the Upper Jurassic mudrock and Fuller's Earth representing the Lower Tertiary mudrock encountered in the North Sea. Some commonly used water-based muds such as KCI/CMC, Polyamine, Polyamine + glycol, water and a newly designed water-based mud system were used to assess the swelling behaviour and factors governing the behaviour of the mudrocks.