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Collaborating Authors
Halliburton Services
SPE Members Abstract This paper details the use of coiled tubing for spotting cement plugs without a workover rig present, during abandonments of 100 shallow, thermal wells in the South Belridge Field. This method decreased the cost of this portion of the abandonment operation by $2000 per well. The paper describes why multiple well abandonment programs are common in thermal fields. The requirements for effective abandonment in thermal fields are also covered. Workover rig and coiled tubing abandonment methods are discussed and compared. The methodology used for selection of an effective and less expensive thermal abandonment cement slurry is outlined. This paper shows that if operating, service company and regulatory agency personnel work together, the cost of abandoning wells can be substantially decreased without decreasing the effectiveness. Introduction Plugging and abandoning shallow oil wells is a routine, but necessary piece of business that has been done in much the same way for the last 40 years. Currently, there are over 1000 idle wells in this area of the South Belridge Field. Eventually, these idle wells and the currently active 2700 wells will need to be plugged and abandoned. In the last 10 years, over 2000 wells have been abandoned in this field. The cost to abandon idle wells accounts for a significant portion of the operating budget for the field. Decreasing the cost of abandonments affects the profitability and economic life of the field. Over the years, for shallow, thermal wells, the conventional method of abandonment has been for a workover pulling unit to remove wellbore equipment and to fill the wellbore with abandonment cement. In 1992, 200 shallow, thermal wells in the South Belridge Field were abandoned. During one-half of the abandonments, coiled tubing was used to place the cement plug after the wellbore equipment had been removed and the workover unit moved off location. This process decreased the cost of an average abandonment by $2000 compared to spotting cement plugs using a workover unit. This method also increased the efficiencies of all involved parties. This paper will detail :1. Reasons for multiple well abandonment programs in thermal fields.2. Requirements for effective abandonments.3. An abandonment method using workover units.4. An abandonment method using coiled tubing units.5. A comparison of the two methods.6. Selection of abandonment cement. Multiple Well Abandonments in Thermal Fields As thermal projects mature, large numbers of up-dip wells become desaturated and uneconomical to produce. The thermal recovery process is mostly controlled by structural dip and gravity drainage. Because of the high (greater than 10,000 cP) initial oil viscosity before steam injection, close well spacing is needed to efficiently recover the reserves. Most of South Belridge Field is developed with between 9 and 13 wells per 5-acre flood pattern. P. 587^
- North America > United States > California > San Joaquin Basin > South Belridge Field > Tulare Formation (0.99)
- North America > United States > California > San Joaquin Basin > South Belridge Field > Diatomite Formation (0.99)
- North America > United States > California > San Joaquin Basin > Belridge Field (0.99)
SPE Members Abstract This paper describes the dynamic and static filtration characteristics of four different drilling fluids under downhole conditions. Filtration rates were measured over two-, four- or five-day periods in a simulated sandstone formation. The drilling fluids studied had a wide range of API fluid loss and rheological characteristics. The API fluid-loss for all drilling fluids tested were generally higher than the filtrate loss observed in the sandstone formation. The largest static and dynamic filtration rates were seen in drilling fluids having uncontrolled fluid-loss properties. A large spurt loss volume, varying in duration from 30 seconds to five minutes occurred upon initial contact of the drilling fluid with the formation. A steady state filtration rate was quickly reached following the initial spurt loss. Dynamic filtration rates and the percentage of circulatable hole varied as a function of the drilling fluid flow rate in the annulus. Increased annular flow rates produced higher dynamic filtration rates. The dynamic filtration rates decreased prior to day four of the tests, after which no significant changes were observed. Removal of the external wellbore filter cake using mechanical scrapers did not significantly change the dynamic filtration rate. The results presented can be used to estimate the effect of flow rates, fluid loss, and rheology of the drilling fluid on the amount of drilling fluid filtrate lost to the formation and on the percentage of the annulus that is circulating. Introduction One of the most important functions of drilling fluids is to minimize the amount of drilling fluid filtrate entering the hydrocarbon bearing formation. Drilling fluids and drilling fluid filtrates may cause formation damage due to fines migration, rock wettability changes, drilling fluid solids plugging and formation water chemistry incompatibilities. The current API RP13B-1 specifications for fluid-loss control conducted on filter paper do not reflect the downhole filtrate loss and filter cake deposition-erosion process. The API test, at best, gives a qualitative comparison of fluid-loss properties. A number of laboratory studies have been conducted to emulate filtration losses under downhole pressure and temperature conditions. Laboratory drilling fluid circulation equipment has been designed to provide borehole annular shear rates, temperatures and pressures. These laboratory designs, however, have always been limited by formation length (less than 1 m) and have not duplicated downhole functions such as pipe movement and mechanical filter cake removal under flow conditions. Recently, the first attempt at downhole fluid-loss measurement was described for a series of four wells in the Mississippi delta. These wells were shut in and the amount of filtrate loss was determined by the annular volumes lost to sandstone formations. As a prelude to this investigation, Smith and Ravi described cement displacement efficiency as a function of drilling fluid properties in a full scale wellbore. P. 395^
PC-Based Cement Job Simulator Improves Primary Job Design
Kulakofsky, David (Halliburton Services) | Henry, S.R. (Halliburton Services) | Porter, David (Halliburton Services)
SPE Members Abstract Until recently, cement simulation programs have been difficult to use, required large computer systems, and occasionally yielded results that were difficult to understand. Often the data input task was cumbersome enough to limit usage of these simulators. With the advent of Graphical User Interfaces (GUIs), even the most sophisticated simulator can be easy to use. With the wide variety of today's PC Graphics packages, complicated results can be made comprehensible through visual displays. This paper describes a technically advanced PC-based primary cement job simulator illustrating how a simulator can be sophisticated and easy to use at the same time. The simulator description includes recent enhancements, such as the capability to utilize temperature-dependent rheology and Critical Reynolds Number when calculating frictional losses. Discussion Access to an effective primary cement job simulator is an important part of a sound cementing program. A simulator provides the designer with a tool that can be used to fine-tune job designs, helping to obtain the safe completion of all planned cement jobs. A truly user friendly program will require minimal training, reduce design time, and be used more often. A GUI and extensive error checking routines are required if a complex, technically advanced simulator is to be considered user friendly. The PC platform was chosen to allow widespread use this software. User Interface The man-machine interface (MMI) plays an important role in the ultimate success or failure of any piece of software. For this reason a GUI was chosen for use as the MMI. By providing a GUI the complex task of transferring, from the user to the computer, the information required by this simulator is simplified. In addition to simplifying the transfer of information, a good interface helps in seeing that the information transferred is the information that is actually required. The subject GUI accomplishes this task with extensive error and range checking features. Any problems or unusual values are reported to the user through a series of warning and/or error messages written in plain English. Uncaught, these input efforts might result in non-english compiler-generated error messages. Simulator In common with other primary cement simulators is the capability of pumping various fluids at different rates through changing tubular and annular diameters. Like other sophisticated simulators, this model can also handle freefall, hookload calculations, foamed fluids, and shutdowns. P. 731^
- Information Technology > Graphics (1.00)
- Information Technology > Human Computer Interaction > Interfaces (0.75)
Windowing Systems Enhance Computer Simulation
Fife, L.D. (Halliburton Services) | Henry, S.R. (Halliburton Services)
SPE Members Abstract Historically, simulation has been performed on mainframe computers, obtaining input through a text file. Creation of the input data file was error prone, and use of the simulator was often difficult. Debugging an input file containing erroneous information was difficult and time consuming. When error checking occurred, it was often within the simulator and fatal errors would result in wasted execution. These computer systems were often remote and expensive to use. The increased speed and capacity of computers allows simulations to be performed on increasingly complicated problems. Application research allows processes to be represented more precisely. As simulators and computers become more complex, creation and debugging of input data files becomes more difficult. The difficulty of required simulations, coupled with the enhanced speed and capacity of available machines, increases the difficulties associated with interfacing the engineer with the simulation and data file creation processes. In particular, the availability and capacity of desktop computers eliminates the need of mainframe computers for many simulators. This solves many of the cost problems associated with remote mainframe computers. However, the human-machine interface provided under desktop computer operating systems is not a significant improvement on the mainframe environment. Using a graphical user interface (GUI) can improve the environment encountered by the engineer, provide sophisticated data checking, and provide other enhancements to the simulation process. The GUI can offer solutions for many of the input file and data error difficulties. Discussion GUI's provide several enhancements to the simulation. These include increased ease of data handling, error checking before simulator execution, improved output handling facilities, simplified access to the operating system, and on-line help. P. 725^
- Information Technology > Graphics (1.00)
- Information Technology > Data Science (0.78)
- Information Technology > Hardware (0.77)
- Information Technology > Human Computer Interaction > Interfaces (0.56)
Rigless Slimhole Drilling
Courville, P.W. (Halliburton Services) | Maddox, S.D. (Otis Engineering Corp)
ABSTRACT The evolution of coiled tubing (CT) and hydraulic workover (HWO) equipment has changed various concepts concerning drilling operations. A new system that combines these two proven technologies can now perform slimhole drilling operations without the use of a conventional derrick-based drilling rig; hydraulic workover equipment provides the capabilities to handle and set the casing program, and by using a continuous drill string, the coiled tubing equipment does the drilling. This combination provides a viable alternative to normal drilling-rig operations, and in addition, increases the number of options available to the operator for solution of drilling and completion problems. Use of the system can enhance cost efficiency, alleviate equipment availability delays, and reduce environmental impact. The system is designed to work under pressure, which facilitates drilling while under balanced and subsequently provides formation protection. Additional advantages of rigless drilling over conventional derrick-based drilling include:Increased system portability Decreased system size Enhanced pressure handling options. This paper describes the components of the system, including the required hydraulic workover equipment, the coiled tubing components, and other necessary elements such as fluid handling equipment. Procedures are presented for drilling and completing a well without the use of a conventional, derrick based drilling rig. The components that make up the bottom hole assembly are also discussed for both normal and horizontal drilling scenarios. INTRODUCTION Current need, application, and advantages of the system The availability of alternative methods for performing an operation is invaluable to an operator in providing job-planning flexibility. In drilling, for example, particular concerns involve equipment availability, environmental impact of moving and operating the rig, and cost consideration in general. In addition, in normal drilling operations, there must be a sound surface or structure upon which to erect the derrick that is capable of supporting the cumbersome size of the derrick as well as the pipe weight. These concerns are successfully managed with this new method for drilling since use of a large derrick is not required. HISTORY HWO Development Because of their small size, the first hydraulic workover units were used primarily for moving pipe within the production string or for moving small production strings. Today's hydraulic workover units have grown in capability far beyond the units introduced into service in the 1960's. Maximum downward forces ("snubbing") that this equipment can exert have increased from 30,000 pounds to 300,000 pounds. Maximum pulling forces have increased from 60,000 pounds to the current 600,000 pounds, and bore sizes have increased from 4-1/16 inches to the current 11 inches. Pipe handling capability of the larger units now includes 9-5/8-inch casing. These capabilities (Table 1) along with a newly-developed series of related surface equipment, such as 1l-inch slip bowls that have been pull tested to 900,000 pounds, allow for the running and setting of many casing programs as well as production strings.
Summary Few studies have dealt with the flow behavior of concentrated suspensions or slurries prepared with non-Newtonian carrier fluids. Therefore, the purpose of this investigation is to present experimental results obtained by pumping various hydraulic fracturing slurries into a fracture model and gathering data on differential pressure vs. flow rate. Several concentrations of hydroxypropyl guar (HPG), a wide range of proppant concentrations, and three test temperatures were studied. The effects of such variables as polymer gelling-agent concentration, proppant concentration, test temperature, and fracture-flow shear rate on the rheological properties of slurries were investigated. The correlations for predicting the relative slurry viscosity for these HPG fluids are presented. Substantial increases in viscosity of fracturing gels were observed, and results are discussed in light of several affecting variables. Results also are compared with those available for Newtonian and non-Newtonian concentrated suspensions. Application of these correlations to estimate the hindered particle-settling velocity in the fracture caused by the presence of surrounding particles also is discussed. The correlations presented can easily be included in any currently available 2D or 3D fracture-design simulators; thus, the information can be applied directly to predict fracture geometry and extension. Introduction During the hydraulic-fracturing process, viscous fluid often is pumped down the well under high pressure to initiate and extend induced fractures. After this stage, another viscous-fluid stage containing proppant is pumped to maintain the fracture geometry created by the previous clean viscous-fluid stage. The other function of the proppant-laden fluid stage is to keep the created fracture open after pumping stops. Fracture geometry and extension during treatment depend largely on the rheological properties of the clean and proppant-laden fluids. Proppant settling and distribution in the fracture also are affected significantly by slurry rheology. Rheological characterization of clean fluid (i.e., fluid without proppant) is relatively well-addressed. However, the rheological characterization of proppant-laden fracturing fluids or slurries is not well-investigated currently.
Field Tests of Downhole Extensometer Used To Obtain Formation In- Situ Stress Data
Kuhlman, R.D. (Halliburton Services) | Heemstra, T.R. (Halliburton Services) | Ray, T.G. (Halliburton Services) | Lin, Peng (Halliburton Services) | Chariez, P.A. (TOTAL Compaignie Francaise des Petroles)
Abstract Knowledge of formation rock properties, in-situ stress direction, and stress magnitudes are valuable aids to the successful drilling, completion and stimulation of oil and gas wells. These factors are of even greater importance for horizontal or highly deviated wells. Problems such as wellbore collapse, breakout, and breakdown during drilling and completion can be minimized by using knowledge of in-situ stress direction and magnitude to optimize wellbore direction and/or mud weight. Knowing the azimuth of hydraulic fractures will be of great benefit on any producing or injection well. For horizontal or highly deviated boreholes, this information may be required to avoid premature screenout and unexpectedly high treating pressures if the well is fracture stimulated. These problems can be addressed with improved mud weight control during drilling and stimulation treatment designs based on knowledge of the stress magnitudes, the direction of the principal stresses, and the formation's mechanical properties. A downhole extensometer tool has been developed (jointly by TOTAL and Halliburton) and field tested that will monitor borehole deformation responses to pressuring before, during, and after a microfracture stress test. The borehole strain measurements before and after fracture initiation are used to determine the following parameters:Minimum in-situ stress magnitude (closure pressure) Fracture direction Width of induced fracture In-situ shear modulus Introduction The concept of using a downhole tool to measure deformation is not a new idea. Pressure chamber tests were performed in mines using strain measuring devices placed in a tunnel section and sealing off that section using bulkheads. Strain measurements were taken as the borehole was pressured. Other devices such as the dilatometer have been devised for testing boreholes. This device consists of a metallic cylinder inside an easily deformed rubber or steel jacket. Pressure is applied uniformly to the formation by means of a fluid positioned between the cylinder and the rubber or steel jacket. Strain measurements are taken from the jacket's deformations during pressuring of the tool. Other devices have been developed which may be used to create double fracture for measurement of the minimum and maximum principal horizontal in-situ stresses. A downhole device which uses pistons under pressure to produce deflections on a borehole has also been developed for determination of rock properties.' The concept of the new downhole extensometer was introduced first by Charlez et al. in 1987. The downhole extensometer which is discussed in this paper differs from the others in that it is used during a hydraulic fracturing process. The device uses caliper arms to measure borehole deflections before, during, and after creation of a hydraulic fracture to determine in-situ properties of the formation. This tool optionally uses one or two conventional compression-set testing packers for isolating a zone of interest. The tool is used to test an open hole section, usually during the drilling operation. This device employs two sets of six arms utilizing linear variable differential transformers (LVDTS) for accurately measuring small borehole displacements. In addition to the radius and displacement readings from the 12 arms, bottomhole pressure, temperature, and tool orientation data are acquired via wireline using a surface data acquisition unit, where these measurements are recorded and monitored in real time. P. 625^
- Europe (0.68)
- North America > United States (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.49)
Abstract Control of acid fluid loss during fracture acidizing treatments is recognized as being a dominating limiting factor in the effective use of such treatments. This paper will discuss the importance of adequate acid viscosity, proper acid concentration, and proper particle size distribution for maximizing acid fluid loss control. The recommendations are based on laboratory testing which utilizes a severe acid fluid loss test. The test involves the use of a hollow core reactor under conditions of several hundred psi radial pressure drop across about a 5/8 inch thick wall. The pressure drop was from the inside of the limestone core to the outside. Parameters investigated included acid viscosity, acid concentration, and fluid loss additive particle size distribution. It was discovered that simply viscosifying the acid provided a remarkable improvement in acid fluid loss control. This enhancement was most pronounced in very low permeability limestone cores. The nature of the viscosifying agent was found to be a secondary effect with polymeric materials being more effective than surfactant type viscosifiers. A viscosity of 20 cp at 511/sec at the treating temperature was found to be an optimum value. It was also shown that the higher acid concentrations caused poorer fluid loss control. The effect of particle size distribution of a silica fluid loss additive was studied and indicated the particles with sizes larger than 80 mesh were key to successful acid fluid loss control. Silica flour was found to provide little enhancement of acid fluid loss control. The principles learned from the laboratory tests can be used to design improved fracture acidizing treatments. Indeed, these principles have been used successfully. Introduction The use of fracture acidizing has been a very successful stimulation technique for improving the productivity of medium to very low permeability limestones. The problems associated with fracture acidizing include the classic problems of fracture mechanics and dynamics during stimulation, closure, and production. Fracturing with proppants presents unique problems in that development of adequate fracture width is critical to the successful placement of the proppant. This width is strongly affected by fluid rheology and fluid leakoff. Failure to properly address both of these areas can yield catastrophic results and a wellbore full of sand. An attraction of fracture acidizing is that it is impossible to "screen off" an acid treatment. P. 81^
- 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 Completion > Acidizing (1.00)
Perforation Friction Pressure of Fracturing Fluid Slurries
Willingham, J.D. (Halliburton Services) | Tan, H.C. (Halliburton Services) | Norman, L.R. (Halliburton Services)
Abstract Even though pressure drop across perforations for clean fracturing fluids can generally be accurately predicted, it is not well understood for fracturing slurries. In this paper, two wellbore models-one transparent and one high pressure-were used to study the perforation friction pressure behavior of sand laden fluids. The transparent model constructed with cast acrylic allowed visual observation of fluid exchange in the "rat-hole" and flow patterns of the slurries in the wellbore and through the perforations. Critical velocity at which sand begins to screenout at the perforations was also determined. Tests were performed in the high pressure model varying gel concentration, sand concentration, proppant size, and perforation diameter to gather pressure drop data. The effect of the ratio of perforation diameter to the average proppant size on the sand screenout tendency at the perforation was also investigated. A correlation to predict the change of perforation coefficient due to proppant erosion was developed from the laboratory data. This paper presents a field procedure to better estimate the change of perforation coefficient during proppant stages for calculating the change of perforation friction. Incorporating this change of perforation pressure drop during proppant stages in the real-time bottomhole treating pressure calculation will enhance interpretation of the treatment analysis. Introduction During a fracturing treatment, fluid containing proppant is pumped down a tubular string, through perforations, and into a fracture. Without a bottomhole tool or reference string, the bottomhole treating pressure is calculated from the following equation. (1) where: BHTP = Bottomhole Treating Pressure (psi) Pw = Wellhead pressure (psi) Ph = Hydrostatic pressure (psi) Pf = Fluid friction pressure in tubular goods (psi) Ppf = Friction loss across the perforations (psi) Using an on-site computer system to perform real-time fracturing pressure analysis to predict fracture propagation requires reliable estimates of the BHTP. P. 479^
- North America > United States > Louisiana (0.28)
- North America > United States > Texas (0.28)
- North America > United States > California (0.28)
Stage Cementer With Integral Inflatable Packer Collar
Borges, J.F. (Halliburton Services) | Turki, W.H. (Saudi Aramco) | Giroux, R.L. (Halliburton Services) | Stepp, L.W. (Halliburton Services)
Abstract Lost circulation during primary cementing is a common problem in the Middle East area. To overcome this problem, operators have commonly used a stage tool with an integral packer element. Often, these elements are inflatable, since most mechanical packer elements have limited differential pressure capabilities. To improve and simplify the operation of stage cementing integral inflatable packer collars (SCIIPCs), designers have developed an opening system that has no moving parts. This system, featuring replaceable rupture disks, has been successfully tested in the US and Middle East. This paper describes the SCIIPC itself, the lab tests required before it could be run, and presents test results. The paper also presents actual case histories featuring the new system during initial field testing. Background The key feature of the new opening system design is a rupture disk arrangement (Fig. 1). Although only one rupture disk can be opened at a time, the design helps eliminate problems caused by tight tolerances between sliding parts-a weakness in previously used opening designs. To date, approximately 200 jobs have been run using the SCIIPC with the rupture disk opening design. In all cases, the tool has opened. Test Procedures Pressure and Flow Tests Initial pressure and flow tests were performed on the rupture disk design in December, 1990. The 9 5/8-in. SCIIPC was modified to allow designers to disassemble the tool after operating it. After the tool was assembled, a joint of 9 5/8-in. casing was placed in each end of the tool; the entire assembly was then placed on two supports located 50 ft apart, with the tool located 25 ft from each support. A downward load was applied at both ends of the SCIIPC to bend the tool/casing assembly. Researchers were then able to measure the downward deflection of the SCIIPC. P. 329^
- North America > United States (0.66)
- Asia > Middle East (0.66)
- Well Drilling > Casing and Cementing (1.00)
- Well Completion > Well Integrity > Zonal isolation (1.00)
- Well Completion > Completion Installation and Operations (1.00)