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Collaborating Authors
Drilling fluid management & disposal
Abstract The fluid-loss behavior of cement slurries and its relation to rheological properties is being examined using a dynamic fluid-loss apparatus. This instrument has the capacity to test slurry dehydration by sequential displacement of drilling muds, spacers, chemical washes and cement slurries through a drilled hole in a formation core. Dehydration of cement slurries containing a cellulose-based fluidloss additive was investigated as a function of flow rates and pressures. Results of these tests show that rapid cement water-loss occurs, followed by a reduced fluid-loss rate which remains constant with time. However, dehydration of cement slurries under static conditions results in decreasing fluid-loss behavior with time. Cement fluid-loss control under dynamic conditions was examined as a function of pressure, temperature, fluid-loss additive concentration, pressure, temperature, fluid-loss additive concentration, and slurry velocity. The effects of sequential displacement of drilling muds, chemical washes, and spacers by a cement slurry upon fluid-loss control was also investigated. While there is clearly much more work needed to understand fluid-loss control under dynamic conditions, it is apparent from these results that the static method of fluid-loss testing is not relevant to the deposition of filter cakes under dynamic conditions. The understanding gained in this work will be instrumental in designing cementing treatments with minimal cement slurry fluid-loss. Introduction Fluid-loss additives are used in cement slurries to assist in maintaining a constant water-to-solids ratio by reducing water-loss to permeable formations. Inhibition of cement slurry dehydration during primary cementing operations allows greater cement primary cementing operations allows greater cement fill-up, maintains initial viscosity, and reduces formation damage. It will also reduce the possibility of annular bridging by dehydrated cement. The present laboratory testing for evaluation of fluid-loss consists of application of pressure to a cement slurry in a standard filter cell? The water-loss through a 325-mesh screen is measured as a function of time. This type of testing is basically static in nature with the actual cementing operation taking place under dynamic conditions. The term, dynamic, refers to fluid motion along the core surface and static refers to the lack of motion. In addition, present cement fluid-loss testing does not take into present cement fluid-loss testing does not take into consideration the deposition of a mud cake with sequential displacement of the drilling mud by washes and spacers. Previous studies of dynamic filtration of drilling muds have shown that water-loss from a circulating mud is greater than shown by static test results. However, there has been no dynamic study of the effect on cement fluid-loss behavior through a formation face by displacement of drilling muds, spacers, and chemical washes by cement slurries. This study deals with dynamic filtration of cement slurries as a function of differential pressure, temperature and flow rates through a hole in a pressure, temperature and flow rates through a hole in a formation core. In addition, cement water-loss behavior was further investigated by displacement of drilling muds and chemical washes by a cement slurry. The effect on cement water-loss of the deposited mud cake on the formation surface was studied by mechanically removing the mud cake. This process would correspond to using scratchers during a cementing operation. EXPERIMENTAL PROCEDURE A schematic diagram of the test equipment used to study dynamic fluid-loss behavior of cement slurries is shown in Fig. 1. An adjustable, triplex pump unit which is capable of flow rates up to 315 cc/sec was used to circulate the slurries through a 1.27-cm bore in a 20.32-cm ร 6.35-cm Berea sandstone core held in place by two pressurized pistons. Velocities up to place by two pressurized pistons. Velocities up to 350 cm/sec (11.5 ft/sec) could be obtained as a result of the formation bore size.
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Well Drilling > Casing and Cementing > Cement formulation (chemistry, properties) (1.00)
Abstract Leakoff control is the key to effective stimulation of carbonate reservoirs by acid fracturing. Converting the acid to a stable foam is one method of greatly improving control of fluid loss to the formation. This method is particularly useful at high temperatures since most of the commonly used fluid-loss additives are destroyed by acid at elevated temperatures. Foaming the acid not only provides fluid-loss control but retards acid reaction rate. Acids are easily converted to a stable foam by adding a foaming agent and injecting gases at the surface. For high temperature applications, foam stabilizers can be added to the acid to enhance foam stability. This paper presents data showing the effect of foam quality, permeability and temperature on leakoff rate in limestone cores. Recommendations are presented for improving the effectiveness of foamed acid treatments. Also, field results are presented to show the increased effectiveness presented to show the increased effectiveness of stimulation treatments using foamed acid. Introduction One of the most difficult problems encountered in well stimulation is the control of fluid loss during acid fracturing treatments. Most commonly used fluid-loss additives are either destroyed by the acid or rendered ineffective at elevated temperatures. The constant and rapid acid erosion of the fracture faces further camplicates the problem by preventing filter cake formation. Foams present a new approach for achieving acid fluid-loss control. Previous laboratory studies have demonstrated the effectiveness of foam as a fracturing fluid, emphasising its fluid-loss-control properties. These same properties have also been properties. These same properties have also been attributed to foamed acid; however no substantiating data have yet been presented This paper presents laboratory data describing fluid-loss-control properties of foamed acid against limestone and illustrates the difference observed between acid and nonreactive foamed fluids. ACID FRACTURING Leakoff control during acid fracturing treatments has proved to be of prime importance in achieving optimum stimulation results. Although a number of authors have proposed techniques to control acid proposed techniques to control acid fluid-loss, new and more efficient methods are constantly being sought. Most conventional fluid-loss additives control leakoff by depositing a low permeability filter cake against the fracture face. Fluid loss is thus reduced by a wall-building mechanism. More recently, foams have been used to achieve fluid-loss control in acid fracturing treatments. One of the advantages of foam is its quality of being a clean fluid, void of particulate fluid-loss additives which may have potential for producing formation damage. Also, since producing formation damage. Also, since foams are not wall-building fluids, leakoff control is not affected by fracture face erosion. The flow of foams through porous-media has been investigated by several porous-media has been investigated by several authors. It has been demonstrated by Bernard and Holm that the effective permeability of a porous media is greatly permeability of a porous media is greatly reduced in the presence of foam.
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Edwards Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (23 more...)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract A new simplified technique has been developed for establishing the carrying capacity of drilling fluids. The procedure involves the use of cutting slip velocity measurements taken in static, or near static, drilling fluids. This value of slip velocity is then used to predict cutting transport for flowing conditions. predict cutting transport for flowing conditions. Equipment was developed which can be used to routinely apply the new technique to field muds. In the new device, the position of the cuttings is detected using piezoelectric sonic transducers. This detection procedure piezoelectric sonic transducers. This detection procedure was found to be the most suitable for application with opaque field muds. The application of cutting transport data in the determination of optimum drilling practices was also examined through the use of a computer model. Use of the computer model in conjunction with experimentally obtained slip velocities allows the determination of the optimum annular velocity. It can also be used to determine if insufficient cutting transport should be enhanced by increasing drilling fluid viscosity or by increasing the circulation rate. The computer model also indicated that the current drilling practice of maximizing jet impact force almost always results practice of maximizing jet impact force almost always results in the use of a near optimal annular velocity when modern rig equipment is available. Introduction The study of cutting transport has been undertaken by numerous investigators since the inception of rotary drilling in 1900. These previous investigations have attempted to determine the affect of variables that influence the ability of a drilling fluid to transport rock cuttings from the bottom of the borehole to the surface. The term carrying capacity is often loosely used to refer to this ability to transport cuttings. More definitive terms also in common use include cutting transport velocity and transport ratio. The transport velocity, vt, is simply the velocity of the cuttings relative to the surface and is equal to the difference between the Annular fluid velocity, va, and the cutting slip velocity relative to the fluid, vs. (1) The transport ratio is defined as the transport velocity divided by the annular fluid velocity. (2) For positive transport ratios, the cuttings will have a net upward velocity and they will be transported to the surface. Many different correlations have been developed for predicting cutting slip velocity while drilling. In each predicting cutting slip velocity while drilling. In each case, the correlation is based upon settling velocity measurements obtained in static Newtonian fluids. In applying the Newtonian settling velocity correlations to the rotary drilling situation, it is necessary to define an apparent Newtonian viscosity for the prevailing downhole conditions. Unfortunately, the prevailing conditions for cuttings transport during rotary drilling operations are quite complex. The geometry of the cuttings is difficult to describe and varies with formation characteristics and drilling conditions. Drilling fluids are generally non-Newtonian in nature and it is difficult to describe the effective shear rate in the fluid surrounding the cuttings. Shear results both from the movement of the fluid in the annulus and from the relative movement of the cuttings through the fluid. Drill pipe rotation further complicates the situation.
- North America > United States > Texas (0.46)
- North America > United States > Louisiana (0.28)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract A major effort has been made to evaluate the commercial application of bits fitted with STRATAPAX Drill Blanks for drilling oil wells. Over 40 field runs have been made with such Diamond Cutter bits and a significant potential economic application of the new material is indicated. Further development work will be required to improve bit design and manufacture as well as the wear and engineering characteristics of the diamond cutters. Introduction Surface-set diamond bits usually contain natural diamonds. The available, as-manufactured, Synthetic diamonds are too small to be used economically in these bits for oilfield drilling. A technique has, however, been developed by the General Electric Company to bind small synthetic diamonds together with a diamond-to-diamond bond on top of a tungsten-carbide substrate. As a result, a relatively large diamond cutter could be produced. The technique was initiated in the manufacture of diamond compacts for machining and dressing purposes. The product was named "COMPAX Industrial Diamond Blank". product was named "COMPAX Industrial Diamond Blank". With the success of this application, these diamond blanks were introduced into the drilling-bit industry. Recently a similar product, named STRATAPAX Drill Blank, was offered particularly for rock-drilling purposes. Mainly during the past few years several companies began to develop bits suitable for fitting with these diamond blanks for use in oil-well drilling. This paper reviews the results of a major effort obtained from over forty field runs with such bits, fitted with either COMPAX or STRATAPAX blanks. Such bits will be referred to as Diamond Cutter bits. In addition, some general information on STRATAPAX Drill Blanks is discussed and results of a number of laboratory experiments are presented. Though a competitive product - SYNDITE is now also available, it has not been product - SYNDITE is now also available, it has not been included in the field tests reported here. WHAT IS A 'STRATAPAX DRILL BLANK'? Examples of a STRATAPAX Drill Blank are shown in Fig. 1. Each blank is made up of a thin diamond layer (minimum thickness 0.5 mm or 0.020 in), firmly bonded to a tungsten-carbide substrate. This layer is obtained by subjecting a mixture of small high-quality synthetic blocky diamond particles and a small amount of catalyst to very high pressures and temperatures. Because of the catalyst selected the diamond layer has only an effective operating-temperature limit of about 700 degrees C, beyond which level the bond between the individual diamond crystals loses its strength. This temperature limitation has proved to be a significant handicap in the development of the processes for attaching the STRATAPAX Drill Blanks to the processes for attaching the STRATAPAX Drill Blanks to the bit, because conventional diamond bit manufacturing methods use temperatures over 900 degrees C. This temperature limitation could also affect the wear of the cutting edge of the bit in actual operation. The diamond layer features a polycrystalline structure without cleavage planes. This is only matched in nature by carbonado diamonds, which have only been used to a limited extent in drilling bits because of their short supply and high cost. The cost of STRATAPAX Drill Blanks is also high, but unlike the carbonado diamonds, the supply of diamond blanks is virtually unlimited. The diamond blank exhibits the following important advantages over the types of natural diamonds generally used in bits for oilfield application:โa generally sharper cutting edge โhigher-quality diamond crystals โa polycrystalline and crack-free structure. These advantages only apply if the temperature limit for the diamond layer is not exceeded. Since this limit may be exceeded during the drilling operations, there is clearly a need for further improvement of the STRATAPAX Drill Blanks. The diamond layer is firmly bonded to a tungsten-carbide substrate, which is about 2.7 mm thick.
- Geology > Mineral > Native Element Mineral > Diamond (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.31)
- Well Drilling > Drill Bits > Bit design (0.48)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (0.48)
- Well Drilling > Drillstring Design > Torque and drag analysis (0.35)
Abstract Due to an uncertainty in the prediction of subsurface temperatures needed to design cement programs in arctic regions, a numerical model has bee programs in arctic regions, a numerical model has bee developed for simulating the heat transfer effects of drilling in regions containing permafrost. The model assumes quasi-steady-state radial heat flow in the wellbore and two-dimensional transient heat flow in the soil surrounding the well. Mud circulation temperature data from two Alaskan North Slope wells have been compared with drilling simulation results to verify the accuracy of the model. The drilling model has been applied to the problem of computing circulating temperatures problem of computing circulating temperatures existing in the wellbore just prior to cementing the 9-5/8-in. casing in place on Prudhoe Bay development wells. Ten variables have been proposed that could have a possible effect on these down-hole circulating temperatures and the results of a sensitivity analysis involving these variables are discussed in this paper. Many of the significant variable effects discussed have not been applied previously to arctic environments. A summary of the parameter study results is presented in the form of three nomographs that permit a rapid calculation of the bottom-hole circulating temperature inside the 9-5/8-in. casing prior to cementing. prior to cementing Introduction The development of the Prudhoe Bay field in Alaska has necessitated several extensive studies by the operating oil companies into the effect of permafrost on drilling and completion practices. permafrost on drilling and completion practices. Although much of this work has involved the mechanics of the permafrost soil in addressing such problems as thaw subsidence and freezeback pressures, the thermal aspect of the permafrost as a heat sink also has led to a number of other engineering problems. Recently, attention has been focused on assessing the influence of permafrost on subsurface drilling temperatures. The accurate prediction of down-hole circulating and formation temperatures is essential in the proper design of the cementing programs involving the 13-3/8-in. casing, the 9-5/8-in. casing, and the 7-in. liner used in the development wells on the eastern half of the Prudhoe Bay field. Estimates of the bottom-hole circulating temperature and the maximum annular temperature just prior to cementing the casing in the hole are necessary in determining the specifications of the cement slurry. Failure to accurately predict these temperatures can result in a flash set if the slurry is underretarded and unsatisfactory compressive strength if the slurry is overretarded. Beginning with Farris in 1941, numerous investigators have studied the convective heat transfer present during mud circulation, and several correlations and analytical methods have been developed for predicting down-hole circulating temperatures. However, these correlations assume nonpermafrost soil conditions and, thus, are not applicable for engineering use in arctic regions such as the North Slope. In this paper, the effect of several drilling variables on subsurface circulating temperatures is discussed for wells on the eastern half of the Prudhoe Bay field. A numerical model has been developed to simulate the convective heat transfer associated with drilling and mud circulation, and the results of a sensitivity analysis using this model are discussed for 10 potentially significant drilling variables. Although the information presented in this paper pertains solely to the presented in this paper pertains solely to the estimation of down-hole circulating temperatures inside the 9-5/8-in. casing for North Slope wells, the sensitivity analysis results should provide a qualitative means of evaluating the effects of several drilling parameters on down-hole temperatures for any arctic region containing a sizable amount of permafrost. NUMERICAL MODEL DEVELOPMENT The use of numerical methods to solve wellbore heat transfer problems is well documented in the literature. A number of papers also have dealt with heat transfer in a phase-changing medium.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Abstract In blowout control and prevention planning, the prime detection instrument needs to planning, the prime detection instrument needs to be designated and its minimum sensitivity specified. Sensitivity requirements will depend on the drilling environment, i.e., casing depth, reservoir properties, mud underbalance possibilities, rig reaction time, circulating rate, etc. Through use of a computer program (KIKSIM) that quantifies the transient characteristics of hydrocarbon gas in the annulus of a drilling well, comparisons are made of detection instrument alternatives. Introduction In an earlier paper, the computer program KIKSIM was used to illustrate how program KIKSIM was used to illustrate how changes in mud circulation rate can aid in well control. The KIKSIM program which develops information concerning the transient characteristics of hydrocarbon gases in the annulus of a kicking well also has considerable value in planning. Among the planning decisions that can be improved with KIKSIM are selection and establishing specifications for mud flow sensors and pit level recorders. The concept of warning time is introduced and stressed. This report deals with the detection of gas in the annulus in drilling ahead situations. It does not deal with detection of formation fluids during trips which is a distinctively different problem. DETECTION STAGES In drilling ahead situations formation gas in the borehole can be detected and measured at three stages, which we will refer to as the entry, mud transport and "expansion burst" stages. Obviously it is to our advantage to try to detect gas as soon as possible, e.g., as it enters the borehole. Since we may at times be dealing with relatively small volumes at bottomhole conditions, this may not always be possible. The second stage during which we may detect gas is during mud transport of the gas up the hole. As mud transports gas up the hole it slowly expands and this expansion can be used to detect gas. The mud transport stage is arbitrarily defined as that period during which the rate of gas ascent is largely (2/3) determined by the mud circulation rate.
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Abstract A technique has been developed to aid the drilling operator in making minimum-cost decisions regarding the selection of casing points. A mathematical model of the typical pressured environment drilling situation is operated on pressured environment drilling situation is operated on by Monte Carlo simulation techniques to generate quantified expected-loss information as a function of the systems various drilling and environmental parameters. Results indicate that it is possible to determine those combinations of mud weight, kick tolerance, and implied formation pressure that preclude further drilling and that economically justify the running of casing. Introduction One of the objectives of optimized drilling is to make as much footage as possible prior to running the next string of casing. prior to running the next string of casing. This philosophy has several advantages, two of which are significant to this analysis:Maximizes the fracture pressure of formations exposed at the most recent casing shoe. Maximizes the amount of hole logged and safety protected by casing during subsequent drilling. In the context of this study, there is also a significant disadvantage to setting pipe at extreme depths, especially where mud pipe at extreme depths, especially where mud weight requirements are known to increase with depth; namely, that the deep-casing philosophy minimizes the margin of safety between open-hole fracture pressure and required mud weight. The name of the game then, is "How deep can an operator drill and set pipe so as to be able to benefit by the advantages and not be overwhelmed by the disadvantages?" A trite, but logical, answer is "Either drill and pay the price of the risks involved, or set pipe and pay the price of new casing, whichever is cheaper."
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- (3 more...)