This paper describes laboratory and field assessments of a series of inhibitive water muds developed by BP. RCS 1 contains cationic starch to control fluid loss and to inhibit shale expansion further. RCS 2 is a highly inhibitive version of RCS 1 containing polyglycerol. RCS 3, the most inhibitive mud of the series, contains a phosphate salt and polyglycerol. Levels of inhibition appear close to those of oil-based mud.
Oil-based drilling fluids are used widely throughout the U.K. North Sea and confer operational and economic benefits to exploration, appraisal, and development drilling activities. These benefits are well-quantified and, without other (environmental) considerations, the use of oil-based drilling muds (particularly those prepared with low-toxicity paraffinic oils) would be even more extensive. Unfortunately, the use of these muds results in the discharge of contaminated cuttings overboard, which consequently damages the benthic community. Addy et al. quantified the extent of the affected zone around development platforms, and restrictions on the discharge of oily cuttings are progressively being imposed on the basis of this and subsequent data. Because of legislative changes, operators have reappraised their drilling fluid programs and have developed a variety of responses, varying from a reversion to water-based drilling fluids to novel methods of oily-cuttings disposal. It is against this background that the present development of inhibitive water-based drilling fluids is taking place. The prime focus is control of the Tertiary shale formations found across much of the central and northern North Sea and Norwegian continental shelf. One of the more successful water-based drilling fluid formulations used to control Tertiary shales to date is the KCl/polymer system. These muds were used extensively for Forties field development drilling in the mid-1970's and early 1980's. Although these wells could be drilled, shale control clearly still was inadequate and mud dilution was excessive. This was both environmentally and economically undesirable. This paper details the development of a series of fluids modeled on the basic KCl/PHPA system at BP Research Centre, Sunbury-on-Thames. Three fluids, RCS 1, RCS 2, and RCS 3, have been developed, and RCS 1 and RCS 2 have been field tested. We will describe the laboratory testing of these fluids and discuss experience gained from the field trials.
Laboratory Development of RCS Mud Systems
The RCS muds were developed after a detailed study of many commercial muds; they are based on the widely used potassium chloride/partially hydrolyzed polyacrylamide (KCl/PHPA) systems. They arose from consideration of the mechanisms by which KCl/PHPA muds are understood to function. Potassium ions retard the expansion of swelling clays (smectites) and, hence, of shales containing these minerals. The high salt levels used in many of these muds also promote clay flocculation by collapsing extended electrical double layers. This helps limit shale dispersion. High-molecular-weight linear polymers, such as PHPA, adsorb on mineral surfaces to form a slick, robust coating that provides a degree of mechanical integrity to shale softened by the ingress of mud filtrate. Bailey et al. suggested that adsorbed polyacrylamide does not reduce either the amount of water taken up by the shale or the degree of swelling but simply provides resistance to erosion by circulating mud. As discussed earlier, it is commonly held that the KCl/PHPA system is the most inhibitive water-based mud in widespread use. This system is adequate for drilling in many areas but still causes severe hole problems when used in very reactive shales. The RCS mud systems demonstrate improvements over the performance of KCl/PHPA muds. Series RCS 1, RCS 2, and RCS 3 each successively increased inhibition of shale expansion. The key components and properties of the fluids follow. properties of the fluids follow. RCS 1
RCS 1 features an additive that increases the tenacity with which PHPA adheres to shale surfaces. PHPA adheres to shale surfaces. In an alkaline mud environment, the edges and faces of exposed clay mineral particles are negatively charged, and, therefore, it is difficult to envisage that significant quantities of anionic PHPA molecules will be strongly adsorbed. The adsorption that does PHPA molecules will be strongly adsorbed. The adsorption that does occur is ascribed to one of several mechanisms, including calcium ion bridges and screening of negative charges on the mineral surfaces and polymers by highly saline fluids. We reasoned that shale inhibition could improve if the charge on the polymer were reduced or, better, reversed. This prompted a study of cationic polyacrylamides and bridging agents. Laboratory tests showed that the greatest improvement in shale inhibition was obtained, not from cationic polyacrylamide, but from a mixture of conventional PHPA and a cationic starch. [Cationic starch is prepared by reacting potato starch with either 2-dimethylaminoethyl chloride or n-(2,3-epoxypropyl)-trimethyl ammonium chloride.] This starch functions to control fluid loss as well as to inhibition. Although RCS 1 contains a cationic polymer, we have not observed incompatibility with the anionic components of the mud (xanthan gum and PHPA). The fluid's response to salt, cement, and drilled solids contamination is similar to that of PHPA muds. We assessed shale inhibition with a series of routine tests: a modified dispersion, an unconfined swelling, and a penetrometer test (see Ref. 12). Shales used in the tests are London (Eocene, swelling, and dispersive), Kimmeridge (Jurassic, nonswelling, but very dispersive), and Oxford (Jurassic, swelling, and slightly dispersive) clays. All shales are preserved specimens taken from working U.K. quarries. Figs. 1 through 3 compare RCS 1 inhibition results with those for several other systems. These results confirm that the combination of cationic starch and PHPA improves control of shale dispersion considerably but does not affect swelling or softening significantly. This is consistent with the enhanced performance of the encapsulating polymer in the RCS 1 system. While RCS 1 significantly but incrementally improves inhibition compared with conventional KCl/PHPA muds, it is still inadequate for drilling the most highly reactive shales. Further improvements in dispersion control and at least some management of the swelling and softening reactions clearly are necessary. These requirements are addressed by RCS 2.
Pericone et al. and Hale et al. extensively discussed the ability Pericone et al. and Hale et al. extensively discussed the ability of water-soluble glycol and glycerol derivatives to control reactive shales. Laboratory work and recent BP field trials of a KCl mud containing one such product, polyglycerol, confirmed that, if used correctly, these materials could improve inhibition significantly.
Summary. In 1988, the U.S. Environmental Protection Agency (EPA) proposed regulations that would set limits of 1.5 mg/kg mercury and proposed regulations that would set limits of 1.5 mg/kg mercury and 2.5 mg/kg cadmium for drilling-waste discharges. To determine potential sources of cadmium and mercury in drilling-waste potential sources of cadmium and mercury in drilling-waste discharges, samples of barite (barium sulfite), formation cores, and commercially available pipe-dope samples were analyzed for total and extractable levels of cadmium and mercury. From this analysis, most of the cadmium and mercury in drilling-fluid discharges , are not available to the environment. The contribution of heavy metals from drilled formation solids is not known before drilling. End-of-pipe discharge limits on metals may compel drilling operators to assume that their wastes could fail the discharge limitation and thus ship all drilling wastes to shore.
Because of the constant concern over discharges of heavy metals by the drilling industry, we examined various sources of heavy metals in offshore drilling waste. The importance of this study is heightened by the Oct. 21, 1988, Federal Register release of the U.S. EPA's proposed Oil and Gas Extraction Point Source Category, Offshore proposed Oil and Gas Extraction Point Source Category, Offshore Subcategory; Effluent Limitations Guidelines and New Source Performance Standards (NSPS); New Information and Request for Performance Standards (NSPS); New Information and Request for Comments. Through the NSPS, the EPA proposed limitations on discharges of cadmium and mercury based on the assumption that the primary source of these metals is the barite component of drilling fluids. For years there has been talk of "clean" vs. "dirty" barite. Yet the NSPS regulations do not consider other sources of mercury and cadmium in drilling wastes. Cuttings from the formations being drilled apparently contribute a significant percentage of the heavy metals found in drilling discharges. The environment apparently is not significantly affected by the discharge of drilling fluids containing trace concentrations of mercury and cadmium because these metals are only sparingly soluble as a result of their form within the Waste Matrix. The study investigated 113 barite samples from mines located throughout the world, 36 cores and formation samples, and three common drillpipe thread compound (pipe-dope) samples as potential sources of heavy metals.
Materials and Methods
Sample Identification and Collection. Barite samples, collected from 1975 to 1989, represent a cross section of the barite available in the drilling-fluids market during that time. The barite mines from which data were available included those in Nevada, Missouri, Chile, China, Greece, India, Ireland, Morocco, and Thailand. We obtained core samples from three major drilling areas (exact sampling locations cannot be published because of the confidential nature of the core samples). Samples 1 through 9 were collected in the Gulf of Mexico, Samples 10 through 19 were collected offshore California, and Samples 20 through 36 were collected in Oklahoma. Core samples were used instead of drill cuttings to minimize drilling-fluid contamination. The coring-fluid composition is unknown and could be a potential source of contamination. Core samples were obtained from wells ranging from 300 to 18,000 ft deep. Samples of drillpipe compound (pipe dope) were field collected from three representative pipe-dope sources.
Chemical Analysis Techniques. Total and extractable levels of cadmium were analyzed in the barite, core, and pipe-dope samples. Total and extractable levels of mercury were analyzed in the barite and core samples. Samples analyzed for total concentration of metals were extracted with Method 3050, acid digestion for sediments, sludges, and soils. Samples were digested with nitric and perchloric acid until the perchloric acid fumed. Samples analyzed for extractable levels of perchloric acid fumed. Samples analyzed for extractable levels of metals were digested with the EP TOX acetic-acid-leach procedure. Samples were analyzed for mercury with the cold-vapor AA procedure. Samples were analyzed for mercury with the cold-vapor AA technique, Method 7471; cadmium samples were analyzed with a flame AA technique, Method 7130.
Proposed Environmental Standards Proposed Environmental Standards The EPA stated in the Oct. 21, 1988, Federal Register that mercury and cadmium discharged with drilling fluids containing barite have a potential to cause environmental problems in the marine environment and a potential for transport to humans through consumption of contaminated seafood, especially shellfish. The EPA originally assumed that barite was the primary source of these heavy metals. It initially proposed a limit of 1 mg/kg mercury and 1 mg/kg cadmium on barite, but the industry argued that the availability of barite at the proposed concentrations was limited and that the limit would increase the cost of barite by 65%. Industry-supplied data indicated that adequate supplies of barite containing less than 3 mg/kg mercury and 5 mg/kg cadmium were available. The EPA proposed a new regulation based on barite containing a maximum of 3 mg/kg mercury and 5 mg/kg cadmium and the average drilling fluid containing 50 wt% barite. The regulation limited end-of-pipe discharges to 1.5 mg/kg mercury and 2.5 mg/kg cadmium. The use of barite would not be regulated, but the discharge of the mud and cuttings would be monitored and regulated.
The Appendix provides a complete record of the results obtained from the analysis. Tables 1 and 2 summarize and Figs. 1 and 2 show the results of analyses conducted for this study. For the samples analyzed, the average mercury content of the barite and core samples was less than the limits of the proposed NSPS regulation. The mercury content was higher in the barite samples than in the core samples. No pipe-dope samples were analyzed for mercury content. Average cadmium concentrations in the pipe dope and the cores exceeded the proposed NSPS regulation limits, while the average cadmium concentration in the barite was less than the proposed NSPS regulation limit. In addition to the total metal analysis, many samples also were tested to determine the extractable concentrations of metals in the sample. Table 3 summarizes the test results, which indicate that very little of the heavy metals in the discharged material is available to the environment.
An end-of-pipe limitation on metals could compel drilling operators to assume that their waste would fad the discharge limitation because the contribution of heavy metals is not known before drilling. Consequently, excessively restrictive cadmium and mercury limits on end-of-pipe discharges may result in costly disposal options that do not benefit the environment significantly.
This paper reports field experience with a new rapid method to detect and count sulfate-reducing bacteria (SRB) accurately. Test results are available in 15 minutes, compared with the 3 to 4 weeks required with traditional culture methods. This new test method detects SRB that grow poorly or not at all on culture media and gives superior results with such solids samples as biofilms, soils, and sludge.
SRB are indigenous to the oil field and cause severe operational problems (i.e., corrosion, hydrocarbon souring, increased problems (i.e., corrosion, hydrocarbon souring, increased emulsions, increased suspended solids, and reservoir plugging) that increase costs significantly throughout the petroleum industry. 14 In addition, the presence of hydrogen sulfide produced by SRB leads to safety and environmental concerns. These problems can be prevented or alleviated by controlling SRB populations. Quick, prevented or alleviated by controlling SRB populations. Quick, accurate SRB population estimates can reduce operating costs significantly, improve oilfield safety, and decrease sulfide releases into the environment.
Historically, SRB have been detected and enumerated in oilfield waters by use of various culture techniques. While several culture techniques commonly are used, the API RP 386 method remains the most widely accepted procedure. SRB, however, constitute a diverse group of microorganisms often interrelated only by their ability to reduce sulfate to sulfide under anaerobic conditions. Isolating, purifying, and identifying many SRB strains are difficult tasks. Furthermore, practical experience indicates that only a fraction of the SRB in the typical oilfield environment win grow on culture media, and growth often is slow. For example, the culture medium specified by API RP 386 grows only lactate-using SRB and requires 28 days of incubation before results may be tabulated. Most SRB media use lactate as the primary carbon source. It is becoming widely recognized, however, that some common oilfield SRB strains do not grow on lactate. In addition, some SRB strains exhibit elaborate trace organic requirements that must be met before they will grow. As a result, an increasing variety of media and incubation conditions are being used to detect and cultivate SRB.
As media formulations become more complex, however, particularly as to potential sulfur sources, the risk of obtaining false results increases. This occurs because SRB culture media actually detect sulfide production and not SRB per se. Therefore, selecting a medium solely because it recovers higher populations of sulfide-producing bacteria does not mean that SRB are also recovered efficiently. As media formulas become more complex, biological communities or "consortia" can develop in the media. These consortia can produce sulfide from sulfite, thiosulfate, cysteine hydrochloride, and other sulfur-containing compounds that might be added to the medium. In fact, SRB may not be present even when a positive result is obtained in such media. The key point is, unless the sulfide is generated stoichiometry from sulfate (under anaerobic conditions), then bacteria other than SRB are involved. Therefore, a simple defined medium with sulfate as the only sulfur source is preferable to grow SRB. However, this leads to a problem: while simple defined media are preferable for proving that SRB are present, many SRB's will not grow on these media.
Clearly, rapid, accurate detection of SRB is highly desirable. It was discovered recently that all eubacterial SRB share a common enzyme, adenosine 5-phosphosulfate reductase (APS reductase), which catalyzes the reduction of adenosine 5-phosphosulfate to sulfite and adenosine monophosphate. APS reductase is required for respiratory sulfate reduction (i.e., dissimilatory sulfate reduction) to occur in the eubacteria. @ enzyme is present in all SRB studied, including thermophiles. APS reductase is not used in assimilatory sulfate reduction and thus is not present in non-SRB eubacteria. This enzyme is present in some colorless sulfur bacteria and photosynthetic present in some colorless sulfur bacteria and photosynthetic microorganisms but not in Significant quantities. It is not known whether the enzyme would be present in any archaebacterial SRB that might be discovered in the future.
With APS reductase as a marker, a highly selective and sensitive immunoassay method was developed and patented to detect SRB. Non-SRB bacteria, including sulfur and sulfite-oxidizing bacteria, do not cross-react with the immunoassay or otherwise impede accurate SRB determinations.
An SRB field test kit was developed from this immunoassay. Tatnall et al. reported laboratory comparisons of this rapid test kit with common culture methods. Horacek and Gawel also reported field tests of an early version of the field test kit. That testing showed that the presence of other bacteria, oil, chemicals, oxidized metals, and sulfide did not interfere with the performance of the test kit in oilfield waters. This paper presents field data obtained with the now commercially available version of the rapid test method.
Sample Collection and Testing. Water Samples. The SRB rapid was field evaluated within several geographically diverse company operating divisions. Water samples generally were collected from producing wells, battery tanks, and various points within water-injection producing wells, battery tanks, and various points within water-injection systems. Usually these samples contained nominal quantities of oil. Depending on their source, some samples also contain small amounts of such normal production chemicals as emulsion breakers, reverse breakers, and corrosion inhibitors. All fluids were tested in an unaltered state. Except where noted, all testing was done on site and consisted of duplicate, parallel SRB population enumerations by different test methods.
Initially, each sample was analyzed for SRB populations by a most probable number adaptation of the standard API dilution-to-extinction probable number adaptation of the standard API dilution-to-extinction test. In some cases, SRB media other than the API medium were used; these occasions are noted. Then each sample was analyzed by the SRB rapid test kit. Each test kit includes detailed instructions; additional information on the test kit is also available.
High-Solids Samples. Samples containing suspended solids often are difficult to analyze. Examples of such samples include biofilms, soil, sludge, and tank bottoms. When < 10 cm3 of sample was processed (usually the case), distilled water was added to bring the analyzed fluid volume to the normal 10 cm3. The test kit was run as usual on this diluted sample, but the SRB result reported by the test kit was adjusted accordingly. That is, if the test result was 1,000 SRB/g, the result was interpreted as being 10,000 SRB/g in the original sample. Instructions are packaged with the test kits. packaged with the test kits. Test-Kit Sensitivity and Scoring Considerations. Each SRB rapid test kit contains a color card to report SRB populations, calibrated with microscopically counted dilutions of a pure culture of Desulfovibrio desulfuricans. The nominal lower detection limit (i.e., least color visible) for the test kit is 1,000 SRB/cm3 of sample.
Four different cement squeezing techniques have been used on wells producing from the Keg River formation in the Rainbow Lake area of Alberta, Canada. This paper evaluates 151 cement squeeze treatments performed at 96 wellsites and compares the use of foam cement vs. conventional squeeze treatments and techniques. Discussion includes key aspects, such as candidate selection, slurry design, treatment design, economic evaluation, and operational considerations.
Cement has been the primary choice as the readily available and easy to apply material to shut off perforations, fractures, channels, and other undesired void spaces. This common practice of placing cement in a desired location to achieve a hydraulic seal is placing cement in a desired location to achieve a hydraulic seal is called squeeze cementing. Squeeze cementing depends heavily on controlled dehydration and accurate placement of the cement slurry at a desired location. I If the reservoir properties are conducive to maintaining placement control, squeeze cementing has proved to be a routine and highly predictable procedure. Formations that will not support columns of predictable procedure. Formations that will not support columns of conventional cement densities (13 to 16 lbm/gal), however, present significant placement challenges. This is particularly true in reservoirs that contain large vugs or natural fractures that can allow whole slurries to enter virtually unimpeded. This lack of placement control probably is the most critical factor leading to placement control probably is the most critical factor leading to conventional cement-squeeze failures. In a number of formations (e.g., the Ellenberger and San Andres in west Texas; the Sadlerochit in Alaska; the Keg River, Wabamum, and Leduc D3 in western Canada; and the Baturaja in Indonesia), squeeze cementing with conventional techniques is difficult because of conditions similar to those mentioned above. These reservoirs typically have in common a low bottomhole pore pressure, highly conductive permeability, significant void space pressure, highly conductive permeability, significant void space resulting from large acid treatments, and in some cases, a low fracture gradient. Most case histories described here involve formations with a low pore pressure and a highly conductive vugular or fracture type of permeability.
Conventional squeeze cementing methods are successful in most reservoirs, so there is little incentive to consider more complex squeeze procedures. In some cases, however, a successful squeeze is difficult to attain with conventional squeeze cementing techniques. A number of attempts usually are made with little success. Invariably, the applied cement volumes are cited as the problem, and sub- sequent squeeze attempts basically repeat the previous procedure, with perhaps an increase in the volume of cement slurry pumped. A number of squeeze attempts usually are necessary for adequate shutoff. Recent innovations in primary cementing have created more choices for squeeze cementing. The advent of a number of lightweight cement systems with such additives as ceramic microspheres, thixotropic agents, and nitrogen gas has resulted in many challenging reservoir placement problems being overcome. The primary difficulty still is matching the most optimum squeeze primary difficulty still is matching the most optimum squeeze cement system and procedure with the properly defined reservoir conditions. Progress has come from experience in the Rainbow Lake area of northwestern Alberta. A pretreatment injection procedure was developed that indicates which squeeze cement system has the greatest probability of initial success. Actual field results were used to probability of initial success. Actual field results were used to help confirm or modify operational guidelines. The advantages of foamed cement for squeeze cementing have emerged from this process. This paper deals broadly with design, job execution, and evaluation. The specific considerations developed for the Rainbow Lake project are emphasized.
Observation of the sudden appearance of annular pressure in wells exposed to high temperature changes or excessive internal casing pressure prompted a laboratory investigation to simulate conditions under which cement sheath failure could occur and thereby define the causes, characteristics, and limits of the problem. Cement sheath failure is manifested by interzonal problem. Cement sheath failure is manifested by interzonal annular-fluid movement and abnormally high annular pressure at some point behind the casing up to and at the surface. Cement sheath point behind the casing up to and at the surface. Cement sheath failure can be observed in any producing area where excessive flowing temperatures exist at the surface or where excessive internal casing test pressures are used. The detrimental effects of cement sheath failure are numerous and may include lost revenue from lost production, potentially hazardous rig operations (especially when annular isolation loss creates shallow-water sands supercharged with gas), and potentially hazardous producing operations. Exposure of steel casing to excessive temperature increases or internal test pressures causes diametrical and circumferential casing expansion. This circumferential force creates a shearing force at the cement/casing interface, causing failure at the cement/casing interface or radial fracturing of the cement sheath from the inner casing surface to the outer casing (or borehole) surface.
In several operating areas, annular-flow problems not attributable to common annular-flow-after-cementing definitions are experienced. This paper is not intended to discuss short-term annular-influx problems. Long-term annular-influx problems usually experienced problems. Long-term annular-influx problems usually experienced after a well begins producing represent a completely different set of circumstances. Long-term annular influx generally occurs after excessive casing test pressures once the cement sheath has set and attained some compressive strength, or following excessive temperature changes resulting from excessively high producing temperatures or steam-injection temperatures. Long-term annular influx has long been believed to be caused by either cement sheath failure or hydrostatic pressure loss in a channeled (bypassed) mud column after the weighting material has settled out of the drilling mud. An extensive investigation was begun to determine the reasons for these long-term annular-flow phenomena. Analysis of cementing systems and well cementing techniques concentrated on the use of "good cementing practices" (i.e., pipe movement; effective casing centralization; sufficient circulation times and rates before cementing for mud and hole conditioning; and sufficient volumes of water, washes, or spacers for hole cleaning). Such current cement sheath evaluation devices as fluid-compensated bond logs or ultrasonic-type logging devices were used to determine the presence of primary cement channels. After analyzing only a relatively few problem wells, it became evident that something drastic had problem wells, it became evident that something drastic had happened to the cement sheath in each well. In all the wells investigated, clean cement was circulated to surface with no indication of lost circulation or fallback; however, the presence of a cement sheath was not evident. The only evidence of cement in the annulus visible on the bond logs was an approximate 50% decrease in amplitude; no evidence of casing or formation signal was visible on the microseismogram of the bond log. The presence of a cement sheath was extremely difficult to prove on the ultrasonic logs as well. Without evidence of a viable cement sheath on any of the logging devices, the existence of a mud channel in the primary cement sheath was difficult to ascertain. With the understanding that full circulation was attained during primary cement placement, gas-cut cement is readily identifiable on ultrasonic logging devices, cement particles cannot enter formation-matrix permeability, and cement (once it has set) does not magically disappear from the annulus, it was readily apparent parent that something had destroyed the cement sheath.Further investigations indicated that all these production casing strings had been exposed to either high internal test pressures or high surface flowing (or injection) temperatures.
The lack of systematic analysis of the hydraulics involved in air drilling has inihibited the development and utilization of air-drilling technology because the optimal design of any drilling program requires thorough knowledge of the wellbore hydraulics. A comprehensive study of air-drilling hydraulics yielded the system model used as the basis for a viable systematic set of design procedures. The system model was developed by coupling the models for air flow in the drillstring, air flow through the bit nozzles, and pneumatic transport of cuttings in the annulus. The resulting system model was used to design an air-drilling program. A set of design procedures is outlined to predict the standpipe pressure, to estimate maximum well depth, and to determine the optimal air flow rate required in air drilling. Practical examples are presented to test these design procedures.
The many advantages associated with air drilling over conventional mud drilling are well-known. Field experiences has demonstrated conclusively that, despite its seemingly limited application, air drilling has succeeded in many areas where mud drilling has failed. Air-drilling technology is underused and has not realized its full potential in the drilling industry. According to reliable estimates, about 30% of all wells drilled in the U.S. could use air drilling successfully; the current actual figure is about 10%. The main reason for this underuse is the lack of a systematic, fundamental design procedure. The few methods available often lack the rigorous analytical bases demanded of modern engineering practice. To stimulate greater use of this viable and cost-effective alternative drilling technique, sound technical bases must be developed, and systematic and proven design procedures and guidelines must be established. These pose a challenge for researchers because of the complexity involved. A system approach is a must. Such an approach must integrate the various components of the air-drilling process, particularly the circulating system, to result in an overall predictive and design tool.
Although several attempts1-4 to develop design methods for air-drilling wellbore hydraulics have been reported, their common setback is that they attempt to predict minimum instead of optimal air requirement. The inherent assumption in these attempts is that the pressure loss in the annulus (and hence the power requirement) increases monotonically with the air volumetric flow rate. As Supon and Adewumi5 discovered, however, the relationship between the pressure loss in the wellbore annulus and the air volumetric flow rate is not monotonic. As Fig. 1 shows, an optimal air flow rate exists that would yield the minimum pressure loss in the annulus. Experiments and modeling have demonstrated that the minimum air flow rate is not optimal. In fact, air flow rates below the optimal rate will cause a much higher pressure loss in the wellbore. In practice, an air flow rate higher than the minimum flow rate must be circulated to prevent cuttings accumulation at the well bottom. As discussed later, the best results can be achieved at the optimal air flow rate. Therefore, these methods only evaluate the lower limit of air flow rate for a given drilling situation instead of generating optimal design parameters.
Angel's1 method is perhaps the best known and most often used. It treats the flow of the air and cuttings in the annulus as a homogeneous mixture (i.e., there is no slip between the air and the cuttings), and this mixture is assumed to have the flow properties of a perfect gas. Angel used Weymouth's equation to derive an expression for the friction factor of the mixture, and as a result, the friction factor is only a function of the annular size. In addition, Angel eliminated the pressure term from the equation by setting the "carrying capacity" of the fluid phase (the momentum of the air) at the bottom of the hole equal to the lifting power of some air velocity at standard conditions, which he recommended to be 152 m/s. The final form of the equation is implicit for air volumetric flow rate. The air volumetric flow rate is calculated by trial and error, and the bottomhole pressure (BHP) can be evaluated from this flow rate. Because of the no-slip assumption. Angel admitted that the circulation rates determined from his method should be regarded as the minimum requirements. Similarly, Wolcott and Sharma4 pointed out that the air flow rate obtained from their method represents the "critical" flow for the given drilling situation. For air flow rates above the "critical" value, drill cuttings will be delivered to the surface; for rates below the critical value, the air pressure is insufficient to lift the cuttings to the surface.
Two fundamental differences exist between the wellbore hydraulics associated with air drilling and with mud drilling: the high compressibility of air compared to mud and the large density difference between air and drill cuttings. These differences preclude direct application of wide experience acquired from mud drilling to air drilling. In drilling, the primary function of the circulating fluid is to clean the hole. For air to clean effectively, an adequate quantity must be circulated. On the other hand, circulating more air than required will result in unnecessary additional compression costs. The key to achieving the maximum drilling rate and realizing a significant cost reduction is to determine the optimal air flow rate, which is dictated by operating conditions and lithological parameters. Unfortunately, no method exists for predicting this optimal lifting velocity for air drilling. To alleviate this problem, a multiphase hydrodynamic model was developed and a thorough analysis of the predictive efficacy of this model was conducted.6-9 Several experimentally observed phenomena are simulated successfully and explained with this model. The optimal air velocity predicted by this model compares very well with the available experimental data. With the predictive capability of this fundamental model demonstrated, the next logical step is to use it to develop a systematic practical design procedure and guidelines for air drilling. This is the objective of this work. Based on this comprehensive model, a set of design procedures for air drilling hydraulics is developed and practical design examples are given for each procedure.
Design of an air-drilling program may call for different strategies, depending on the operational situation. In most field cases, the air flow rate (at standard conditions), instead of the standpipe pressure, is predetermined. In other words, the air flow rate is an independent variable and the standpipe pressure is a dependent variable. The air flow rate could be determined according to the value of optimal air flow rate, or it may be limited by the output capacity of the available air compressor. Three different design scenarios are immediately apparent.
A computer simulator was developed and used to evaluate reverse circulation as a potential well-control procedure during drilling. Potential advantages of reverse circulation verified by the simulator include lower casing pressures and smaller cumulative pit gains. In addition, kick fluids are removed from the well much faster than with conventional kill procedures. Several equipment modifications will be required to implement the reverse-circulation kill procedure.
Such conventional well-control methods as the driller's method or the wait-and-weight method have gained widespread acceptance in the drilling industry owing to their effectiveness and flexibility. These methods circulate kick fluids out of and kill fluids into the well following predetermined and controlled actions that require keeping bottomhole pressure (BHP) constant to prevent additional kick fluids from entering the well while maintaining annular pressures below a maximum allowable pressure limit. Both of these methods have proved effective for hydrostatically stabilizing a well, and each has relative advantages. Recognized advantages of the driller's method are that it is simple and can be applied immediately to begin well-control operations shortly after taking a kick. The wait-and-weight method improves on the driller's method by shortening total circulation time and minimizing maximum annular pressures. But this method results in additional calculations and a delay in the implementation of the well-control procedure, during which well pressures will rise because of an increase in kick fluid (gas). The success of each method relies on a well-trained crew that follows specific procedures. These methods, however, were developed with the basic assumptions that the well can be safely shut in and the kick fluids can be circulated out of the well without exceeding formation fracture or casing burst limits.
During the drilling of almost any well, a well-control situation potentially may occur in which either of these assumed conditions does not exist, precluding the use of a conventional well-control procedure. One such situation commonly occurs when drilling below drive or conductor casing; formation strength is insufficient to shut in the well if gas is encountered (shallow gas problem), and the well must flow through a diverter system. Another situation occurs when a very large kick is taken during drilling of an intermediate hole. While it may be possible to shut in the well initially, the high casing-shoe pressures caused by gas expansion in the annulus may be such that the shoe will fail under these pressures and using a conventional procedure through full well circulation would be unsafe. Typically, one would be forced to operate the choke to avoid exceeding the maximum allowable casing pressure, which, in turn, would allow additional kick fluids into the well.
Equations for calculating casing deflection and determining casing centralizer spacing are derived for 1D, 2D, and 3D wellbores. The load-deflection differential equation for a span of casing between two centralizers is solved by use of the "fixed-ends" boundary condition. The combined effect of casing weight and axial tension on casing deflection is analyzed in detail.
Casing centralizers are used widely in cementing Operations to keep the casing away from the wellbore wall to improve the displacement efficiency and to obtain good cement quality in the annulus.
Because the casing segment between two adjacent centralizers will deflect away from the well centerline in any nonvertical wellbore, this deflection must be considered in the determination of casing centralizer spacing: This will help ensure adequate standoff between the casing and the wellbore wall to achieve a high-quality cement job. For bowspring-type centralizers, displacement of the centralizer itself caused by the lateral loading on the centralizer also must be considered in the design.
A casing string with centralizers may be handled as a continuous-beam problem. The conditions in an underground wellbore (e.g., doglegs) tend to complicate the problem. The correct calculation of casing deflection and centralizer spacing has not yet been published.
This paper presents casing deflection equations that were rigorously derived from the differential equation of the casing deflection in a realistic, crooked wellbore. The results provide accurate estimation of the casing deflection and help clarify some confusing and incorrect concepts in the literature.
Casing Deflection In ID, Straight, Inclined Wellbores Without Axial Tension
In an inclined wellbore without doglegs and with negligible axial tension or compression in the casing, the casing deflection at the midpoint between two centralizers is given by
Casing Deflection In 1D, Straight, Inclined Wellbores With Axial Tension
When the effect of axial tension in the casing string is considered, the casing deflection at the midpoint between two centralizers may be calculated with Timoshenko's equation for the deflection of a straight tie rod:
where = with = as the uniformly distributed lateral force for our case of casing in a 1D, straight, inclined wellbore. Timoshenko's equation (Eq. 2) considering a fixed-ends boundary condition is mentioned in Ref. 5.
Casing Deflection In 2D Dropoff Wellbores
This crooked wellbore lies in the vertical plane with the wellbore's inclination angle decreasing as measured depth increases. We will adopt the usual assumption that this wellbore has a constant curvature between any two survey points.
The maximum casing deflection off the wellbore axis between any two adjacent centralizers is calculated with Eq. 3, which is derived in Appendix A:
Summary. Practical drillstem-failure prevention seems to be based more on individual knowledge of specific failures than on any standard model. To present a broader approach to drillstem-failure prevention, this paper draws on failure-prediction models, failure-investigation results, drillpipe finite-element analysis, and the API/IADC Drillstring Database to construct a unified approach to failure prevention.
Drillstem failures, even such routine failures as drillpipe washouts, can contribute significantly to the cost to drill today's wells. These costs grow exponentially when the failure results in fishing operations, and in extreme cases, failures can even cause well-control problems. In a 1985 study, McNalley reported that 45% of deepwell drilling problems were related to drillstem failures. Moyer and Dale concluded that drillstem separations occurred in one in seven wells and cost an average of $106,000 each. For such routine failures as drillpipe washouts, the failure often is accepted as "part of the business." The offending components are replaced and operations are resumed. If the cause of failure is unusual, analysis sometimes is performed. Results are reported and recommendations are made to prevent similar failures. These failures seem to be handled case-by-case, however, without an overall approach to prevention. This paper summarizes results from analysis of 76 drillstem failures and draws on data from a recently presented report on the API/IADC Drillstring Database. This paper presents a unified approach to decrease drillstem failures on the basis of these results.
Failure Analysis Results
Table 1 summarizes results from analysis of 76 individual drillstem failures that occurred in a variety of drilling conditions in the U.S., Dutch North Sea, east Africa, and Central America. No attempt is made to break down the failures by area or drilling conditions. The 76 failures are simply those that were sent to us for evaluation from 1987 through 1990.
The data are broken down by cause and component (Table 1). Because these data are based on failures submitted for analysis, they are weighted toward the more unusual, higher-cost failures. This is evident when comparing the percent of string separations (46 %) in the sample data with the results in the API/IADC database. The database, which included 1,785 records of drillpipe [not bottomhole assembly (BHA)] failures, recorded that string separations (twistoffs) accounted for more than 5% of all drillpipe failures.
While they are not representative of all failures, the 76 failures Table 1 reports probably can be considered representative of those submitted for analysis; on the basis of these data several significant observations can be made.
1. Tension and torsion failures combined accounted for only 13% of the total failures reported. 2. Fatigue was the primary cause of 50 of 76 failures (65%) and contributed significantly to 10 other failures. Fatigue directly caused 43% of the twistoffs. 3. Low material-fracture toughness was the primary cause of six of the total failures (8%). Each of these failures had a significant fatigue component as well.
When torsion and tension failures were examined individually, in each case where loads could be determined, these loads exceeded the values recommended in widely recognized design practices. Therefore, little that is new can be said about prevention of torsion or tension failures on the basis of the cases presented here. Drillstem design practice focuses on tension and torsion, which probably explains why these mechanisms accounted for so small a portion of total failures.
Fatigue- and material-related failures are another matter; not only did they contribute the lion's share (73%) of total failures, but they also accounted for more than 60% of the twistoffs. Unfortunately, predicting fatigue behavior is far more difficult than predicting drillstring behavior under torsion and tension loading. And while API RP 7G offers some guidelines for fatigue in drillstring design, we believe that the continuing high proportion of fatigue failures provides evidence that fatigue prevention procedures still can be improved.
Fatigue damage and failure occur because the drillstem is loaded cyclically during rotation. The process occurs in three stages, as Fig. 1 diagrams. Stage 1-Initiation. Fatigue damage causes a microscopic crack that grows with repeated stress cycles (Points A to B). Stage 2-Growth. At Point B, the crack has enlarged to the point where it acts as its own stress concentrator and continues to grow with each stress cycle (Points B to D). Stage 3-Failure. Final, sudden fracture of the remaining cross section occurs when the crack reaches critical size (Point D). Critical crack size will vary with part geometry, loading conditions, and material toughness. Point C represents the smallest crack size detectable by inspection.
Fatigue behavior for a given material can be represented by an S/N curve (Fig. 2) or a crack-growth-rate curve (Fig. 3). On the S/N curve, stress amplitude is plotted against total cycles to failure. For steels in a noncorrosive environment, a stress amplitude exists below which fatigue damage will not occur, even after an infinite number of cycles. This stress amplitude is called the endurance limit, SL, for that material. In a corrosive environment, however, no endurance limit may exist, so fatigue damage can occur even at low stress amplitudes.
The fracture-mechanics representation of fatigue-crack growth usually is displayed on a curve similar to that shown in Fig. 3. Here, a crack or crack-like flaw is assumed to exist already, and crack-growth rate per cycle, da/dN, is plotted against stress intensity range, .
Fatigue cracks can grow in one of three ways, depending on stress intensity range, as Fig. 3 shows. In Region 1 (low stress intensities) little or no crack growth occurs with each cycle. As stress intensity increases, the crack behavior enters Region 2, where it grows in a stable manner. As stress intensity approaches the critical level, crack growth becomes unstable, and failure by rapid fracture is expected (Region 3). Because the value of stress intensity includes the effect of geometry (e.g., an elliptical fatigue crack on a drillpipe tube) the concept of a critical crack size presents itself. That is, for a given loading, geometry, and material fracture toughness, a critical crack size exists above which rapid catastrophic failure can be expected by either brittle fracture or gross plastic deformation.
As a result of recurrent, costly failures in high-clearance casing connections, several major operators and connection manufacturers developed and executed a joint industry research project to verify connection performance experimentally. The program involved unique procedures for testing both makeup characteristics and structural performance of the connections, identified inadequate connection designs, and qualified a new generation of improved high-clearance connections.
In 1985, Arco Oil & Gas Co. studied the frequency and cost offlush-joint casing failures that occurred from 1979 to 1985 and found substantial incentive to research flush-connection designs. In 1986, arrangements to address the issue through physical testing in a cooperative joint industry program, DEA-27, were finalized. The Drilling Engineering Assn. (DEA), an industry research operations forum, was the catalyst that made DEA-27 possible. Although the formal project concluded with tests on four products, it also developed test procedures that created a testing standard. These procedures have been followed for tests on three additional products, and the program effectively continues with plans for future additional product evaluations.
DEA-27 has had a major impact on the technology of this class of connections. Successful tests have resulted in the qualification of new true-flush and swaged-style clearance connections. Other tests revealed important performance deficiencies in certain connections. In several cases, shortcomings were addressed with design revisions that allowed for successful qualification. One design revision of this nature led to a unique proprietary seal mechanism. As a result of DEA-27, operators have virtually eliminated flushjoint failures attributed to connection deficiencies and have avoided millions of dollars of associated cost.
This paper presents background data on high-clearance casing failures and their economic impact, which led to this joint industry effort, a discussion of the difficulties in providing high structuralload capacities in flush-connection profiles, an overview of the testing procedures and practices, summary results from the work to date, and recommendations for future efforts.