This case-history paper focuses on the evolution of a novel completion concept. The concept resulted from improvements in through-tubing vent-screen technology and the invention of a wireless casing collar locator (CCL) for coiled tubing (CT) operations. This completion method provides the following:
reduced completion costs
improved completion efficiency
extended completion life
reduced mechanical risk
improved reserve recovery rate
The invention of the wireless CT CCL was a key development that advanced this completion technique.
A new surface-modification agent (SMA) is at the core of this completion process. The SMA is a water- and oil-insoluble, resinous liquid additive that does not harden or cure under reservoir conditions. This additive is applied to proppant during the sand-control portion of the completion process to increase the cohesive forces between the proppant grains. The SMA provides the following advantages:
It can help increase pack permeability and porosity by up to 30%.
It helps control fines migration.
It decreases mechanical risk by helping stabilize the annular pack.
Tests have shown that using of SMA increases the critical flow velocity of the annular pack. It (1) allows the well to produce at higher rates without producing the sand from the annulus or (2) allows the operator to shorten the completion blank length at a given production flow rate, and (3) allows the length of the completion assembly to be reduced, providing flexibility that allows the completion method to be used on wells with closely stacked pay zones.
Before the development of CT CCL, operators had to use CT rigs with an electric line in the tubing to power downhole tools with perforating collar locators or gamma ray (GR) perforators. This system could triple or quadruple job costs. Wireless CCL allows accurate depth measurements with CT, making it possible to run guns and packers on CT with an existing GR CCL log as a reference. The CT CCL eliminates the need for e-line and reduces the completion time and daily spread cost. When the space limitations and the time required for repositioning the equipment for different phases of the operation are considered, the time associated with spotting equipment in offshore operations can be substantial. The CT CCL reduces completion time.
The following case histories describe economically successful jobs performed with these integrated services.
Over the past 5 years, emphasis has increased concerning the recovery of smaller segmented/stacked reserves in the Gulf of Mexico (GOM). The sands in these reserves are often stacked in various sized faulted blocks with reserves ranging from 0.75 BCF to 7 BCF. Fig. 1 (Page 6) illustrates the typical arrangement of these sands around a faulted structure. The use of 3-D seismic, directional drilling/logging technologies and better reservoir understanding has greatly increased the number of wells drilled through stacked pay zones. The single-trip vent-screen system has become a flexible, cost-effective, and viable completion method that is crucial for successfully harvesting stacked pay zones.
Nondestructive Inspection of coiled tubing (CT) and coiled line pipe (CLP) is not only essential in assuring product quality, but also can be useful in determining physical attributes. In this paper are discussed some non-invasive methods that have been found to be useful in assessing these products.
Nondestructive Testing (NDT) offers some new, and several well-developed techniques for assuring product integrity in the coiled tubing (CT) and coiled line pipe (CLP) industries1,2 In this paper, we describe some of those NDT methods that may be used to test for potential problems in both new and used CT and CLP.
Many of the NDT methods used for casing, tubing, drill pipe and line pipe are applicable, with some minor modifications, to CT and CLP. Typically, electromagnetic and ultrasonic methods are employed, and are embraced in the Specification for Coiled Line Pipe3. Other methods are needed to detect or measure specific phenomena, such as accumulated fatigue, which are specific to coiled products.
This paper outlines some problems that have been solved and some recent results that have been obtained with coiled carbon steel tubulars. In many cases there are parallels with the inspection of typical OCTG and LP, while for others, some existing techniques that are used in other industries need to be evaluated for applicability to CT and CLP.
It is commonplace to use electromagnetic non-contact methods wherever possible because of the uncertain nature of the outer surface of the tubing, based upon concerns regarding an even transmission of ultrasound into and out of the tubing surface. Ultrasonic methods are used in special circumstances, such as tube-to-tube and pipe-to-pipe weld inspections. This paper will not cover existing in-line electromagnetic testing but rather some techniques and results that are currently being evaluated.
Requirements for Coiled Tubing and Line Pipe
In assessing the needs of the users of CT and CLP, one must look to how NDT methods can fit to CT and CLP specifications. Typically, the following questions need to be answered:
What are the most effective NDT methods to be used during tubing production, and at what sensitivity levels?
What are the most serious problems encountered in in-service performance of coiled tubular products?
What are the most appropriate NDT methods for detecting and measuring them?
Can fatigue in CT be measured?
How can fatigue and the results of NDT be combined to produce an accurate method of determining in-service tubular degradation?
Can radiography for weld inspection be replaced by other methods, such as ultrasound?
Can rapid prove-up methods evolve, so that new and in-service strings can be quickly verified?
What levels of qualification(s) and certification should inspectors hold?
This paper discusses some potential solutions.
Electromagnetic methods cover eddy current testing (ET), magnetic flux leakage testing (MFL), alternating current flux methods (ACFM), Barkhausen noise inspection, analysis of the hysteresis curve7, etc. Tubulars present a relatively special case because of symmetry, and are therefore often relatively easy to deal with by electromagnetic methods. Some examples are given below.
The paper describes a new coiled tubing conveyed drilling technique, were several new well bores are jet-drilled perpendicular from the mother well and into the reservoir formation. This technology is targeted for Enhanced Oil Recovery (EOR) in both existing and new field developments. The objective is to improve the production profile around the mother well, by penetrating the damaged skin zone, and connecting to possible hydrocarbon pockets left behind in the reservoir.
The Bottom Hole Assembly (BHA) is configured to jet-drill several slim laterals, all in one coiled tubing (CT) run. This through tubing operation has the potential to create up to ten, 50 m long, and 1-2 in. diameter laterals at the exact desired depth in the mother well. The BHA consists of two main parts; a casing drilling machine and a high-pressure hose and jet-nozzle. The hose is spooled from the BHA as the lateral is drilled into the formation.
The main issues presented in the paper are:
The new jet tool functional characteristics
The theoretical aspects of jet drilling; penetration mechanisms and self-induced nozzle pull force
Laboratory experiments (confirmation of theoretical models)
The jet drilling effect on improved well production (production simulations).
The technology is an attractive substitute or supplement to acid and proppant fracturing, perforating services and conventional sidetrack drilling.
An important issue when stimulating a producing or injection well is to control the exact placement and direction of the treatment. This may represent a challenge in conventional fracturing and acid stimulation methods. Stimulating low productivity zones exposed together with good productivity zones represent in many situations a problem, since the treatment is improperly diverted into the low productivity zones. The stimulation fluid tends to flow into the good zones, which in many cases were not the target for the stimulation. Furthermore, fractures may open pathways along the casing wall, causing zonal isolation problems in the well. A variety of diversion techniques have been developed in the industry today, in order to achieve improved stimulation control. The success of these techniques varies.
This paper describes a technology that provides means for improved control of the EOR treatment. The technology provides real time signals, which acquires exact measurements of tool depth and direction. No pre-treatment activities, like pulling tubing (dependent on size), section milling and/or under-reaming is required prior to the jetting operation.
The tool will be a valuable supplement or substitute to conventional services like:
Conventional sidetrack, slim hole drilling.
The Jetting Technology Development Project - Definitions and Functional Descriptions
The tool is a coiled tubing conveyed electrical bottom hole assembly, designed and developed to create a number of laterals perpendicular to the mother well in one CT run. The laterals remain barefoot and are created by means of the jet-impact generated when pumping fluid at high pressure through the nozzle-head. The energy created when the fluid exits the nozzle-head is also providing the required forward force to pull the high-pressure hose into the lateral.
This paper provides an explanation of the concept of the AG-itator, presents field performance results and examines the potential use of the tool in CT (Coiled Tubing) drilling and workover operations. The tool has been widely used as a solution to the major problems associated with slide or oriented drilling. The concept of the tool is based on reducing friction and providing accurate weight transfer to the bit. Typical applications include; sliding with a PDM-PDC combination where previously difficult or impossible; overcoming motor stalling problems; increasing ROP and extending the length of oriented intervals. The technology is to be developed as a CT tool and is expected to be particularly useful, as CT operations are characterised by constant non-rotation and high levels of friction. These two factors ultimately lead to helical buckling which can limit the effective reach of CT drilling or workover operations.
The fluid action of the tool creates pressure pulses that generate an axial force of approximately 15,000lb at a frequency of 16Hz (refer to Fig 1). These pulses gently oscillate the bottom hole assembly (BHA), reducing friction and improving weight transfer. In this way, weight is transferred to the bit, continuously and accurately without harsh impact forces. It has been demonstrated that the tools' fluid action is benign, as it has not damaged the bit, tubulars or more sensitive equipment such as MWD/LWD. Consequently, standard downhole equipment can be used with the tool.
It is argued that accurate weight transfer improves drilling performance in several ways (1) PDC bit life can be extended as the bit is prevented from constantly spudding into the formation. Additionally, both roller cone and PDC bits can be run without the risk of damage to bit teeth or bearings; post run bit characteristics have shown that no damage to the bit occurred as a result of impact forces. (2) Higher levels of WOB can be achieved using lower off hook weight. (3) There is reduced drill pipe compression as weight is transferred effectively and not dissipated at points where the BHA or drillstring hangs up. (4) Tool face control is enhanced. (5) Gross rates of penetration are increased.
Applications for the technology exist in all modes of drilling but usage appears particularly beneficial in non-rotating drillstrings and BHAs. Such applications are increasingly common as well profiles become more tortuous and the limits of extended reach and directional drilling are reached. Run data shows that the tool is a simple way of extending the reach and capability of conventional steerable assemblies. Accurate weight transfer and exceptional tool face control have been logged using PDC bits, even in significantly depleted formations after large azimuth changes. Intervals have been extended and drilled with higher ROPs while problems associated with setting and maintaining tool face have been minimised. The technology is compatible with MWD systems and is a viable means of extending targets whilst improving ROP, reducing rock bit runs and lowering the risk of differential sticking. Before assessing the use of the technology to extend the reach of CT BHAs, it is worth looking at field performance.
Extending the reach of Conventional Steerable Assemblies - A Case History in the Dutch sector of the North Sea
The 5 7/8" section of a development well was to be drilled in the Silverpit, Lower Slochteren and Westphalian formations in the Dutch Sector of the North Sea. The drilling objectives for this section were to build inclination from 42° to 84° at the top of the Lower Slochteren, and then to maintain a tangent before dropping angle to TD. The measured depths were recorded as 3,645 and 4,373 metres respectively. Subsequently, a sub-horizontal drain of 85° was to be drilled by a BHA incorporating the AG-itator (Refer to Fig 4). The purpose of using the technology was to provide accurate weight transfer to the bit during slide drilling, thereby minimising motor stalling, the BHA hanging up and to make tool face orientation easier.
Rispler, Keith (Halliburton Energy Services, Inc.) | McNichol, Joanne (Halliburton Energy Services, Inc.) | Matiasz, Kevin (Halliburton Energy Services, Inc.) | Rheinlander, Mark (Quality Tubing, Inc.)
Coiled tubing (CT) erosion can occur during CT fracturing operations. Resulting wall loss and fatigue can limit CT life and prevent safe wellsite operations. An artificial neural network (ANN) has been successfully developed for accurately predicting wall loss resulting from erosion.
This paper presents a case history in which ANN technology was used to successfully manage tubing strings during CT fracturing operations. During these operations, wall loss affects CT pressure ratings, tensile strength, and fatigue, all of which are critical performance parameters used for determining CT life and identifying a safe operating envelope. An ANN can predict erosional wall loss and quantify critical performance parameters for specific applications.
Hydraulic fracture-stimulation treatments performed through CT provide a cost-effective method of stimulating wells in which producing intervals have multiple stringers. This technique is being successfully applied in many areas and is being used on a daily basis in the shallow gas fields of southern Alberta. Fracturing operations in these shallow gas fields typically require a 2 3 /8 -in. (0.203-in.) QT-900 tubing string that is 2,625 to 2,789 ft (800 to 850 m) in length. The zones targeted for stimulation are located at depths of 984 to 2,362 ft (300 to 720 m). Typical treatments involve three to eight stages in which a total of 110,231 to 220,462 lb (50 to 100 tonnes) of proppant is pumped. In addition, most treatments involve the use of a gas-assist with either carbon dioxide or nitrogen added to the stimulation fluid.
Operating within the safe working envelope of the CT is critical to the success of these operations. Wall loss from erosion affects operational CT parameters, and previously identified patterns of erosion 1 required a better understanding of this phenomenon. Three of the 35 strings used during CT fracturing operations performed in the year 2000 were evaluated for wall loss. Magnetic wall-loss detection was performed with Hall-effects sensors. The strings were measured at 82-ft (25-m) intervals and at 30° intervals around the circumference of the string. The data from one string clearly indicate maximum erosion loss on the outer radius of the pipe and minimal wear on the inner radius of the pipe ( Table 1). Wall thickness for all three strings is plotted in Figs. 1, 2, and 3. The wall loss from the tests demonstrates a repetitive pattern similar to those previously identified. 1 Pipe thickness affects critical CT operating parameters, including fatigue, internal pressure capacity, and tensile/compressive loading. A method for accurately predicting erosion could help operators use traditional CT pipe-management simulators to effectively manage CT fracturing strings.
Using an ANN to Develop a Wall-Loss Model
Several technical papers have been written about the development of ANNs. Neural nets have been given many different names, including black boxes, empirical models, universal approximators, and parallel models. The basic function of an ANN is to map data from one multidimensional space to another. Fig. 4 shows an example of a simple ANN with three inputs, two hidden layers with two neurons in each layer, and one output. The example has 12 unknown weights. The weights must be determined so that the inputs can be properly mapped to the corresponding outputs.
ANNs are constructed of neurons organized in layers. An ANN can consist of a single layer or multiple layers, and each layer consists of one or more neurons. Artificial neurons receive, consider, and calculate input from other sources. This information is then displayed by an algorithmic process or transfer function. The number of layers, neurons in each layer, and connecting transfer functions depend on the problem that must be solved.
In many wells it is advantageous, both economically and operationally to perform stimulation techniques using coiled tubing. More often than not this process will require that the zone of interest be isolated for the treatment to be effective. Several basic means of isolation are available depending on whether the application requires intervention through tubing or into a monobore, or "tubingless", completion. These basic tools require some form of pipe manipulation to set and retrieve, which in straight holes presents little difficulty, but in deviated wells becomes problematic. As the deviation from vertical increases and eventually reaches horizontal, tool manipulation becomes increasingly difficult and eventually impossible.
To address this problem in highly deviated wells a new generation of downhole straddle tools has been developed which requires no pipe manipulation to set and retrieve. These tools, called Fluid Velocity Set devices, use fluid pressure build up created when pumping through a nozzle to activate and relaxation of that pressure to deactivate a tool. Two distinct types of tool have been developed:
Inflatable straddle packers for through tubing applications, which can be inflated to seal in an I.D. up to 2.5 times larger than the running O.D.
Mechanical straddle packers for monobore applications, which have a running O.D. small enough to pass through standard tubing mounted accessories, such as landing nipples and sliding sleeves, and set in the tubing I.D.
This paper will discuss the advantages and disadvantages of commonly used isolation methods and will detail the design, development and testing of these new tools. Using recent field tests the authors will illustrate that this type of tool provides a functional and cost effective method of isolating zones in highly deviated and/or horizontal well sections.
In recent years, the oil industry has been utilizing more highly deviated and horizontal wells, in order to more adequately and economically produce formations. This has in turn presented the Service Industry with many new challenges, not the least of which is the operationally and cost effective stimulation of the resultant well sections. One of the most effective and economical methods employed is the use of coiled tubing, which can be run in a live well, and, with the proper tools, can be used to isolate and treat zones.
The original tools developed for zonal isolation were designed to meet the requirements of two distinct types of completion:
the monobore completion, in which the productive zones are in well sections which have the same I.D. as the production tubing.
The standard completion, in which the well is completed in casing and production is "thru-tubing" in nature.
These requirements resulted in the development of several distinct tool alternatives to suit the two requirements:
The opposed cup type tools (see fig. 1) required the same ID from the start of the tubing to the zone to be treated. The primary advantage of this type of tool was that it did not require manipulation of the coiled tubing to set and seal. However the cup type tool was also limited in the distance it could effectively travel in the tubing ID before resultant cup damage, due to the drag caused by the interference fit, resulted in impairment of its ability to seal. This situation was exaggerated by having to pass through tubing restrictions such as landing nipples and sliding sleeves and by the additional drag associated with highly deviated wells.
There has been a dramatic increase in the use of continuous reeled tubing (coiled tubing) for drilling operations. Much of this increase can be attributed to improvements in the quality and dimensions of coiled tubing itself - pipe sizes have steadily increased over the years from 1 inch OD to 3½ inch OD and bigger. Other developments have included improved downhole motors and, for directional work, sophisticated survey and orienting tools that can be controlled, in real time, from surface.
Despite these developments, CT drilling is still applied to very few wells, or a tiny percentage of the total drilling market. There are many reasons for this including high equipment and personnel costs, low rates of penetration (ROP), and issues related to the reliability of high-cost "smart" bottom hole assemblies (BHA's) needed for directional work. The idea that CT drilling would offer a cheap alternative to conventional rigs is, and probably will remain, an unfulfilled pipe-dream. However, CT drilling certainly has its place, particularly for vertical well deepening and for slimhole multilateral work. The method presented here provides the opportunity to improve the efficiency and lower the cost of such operations. This paper describes a technique that we call Stimulation While Drilling (SWD), a drilling method that is particularly applicable to the use of coiled tubing. In particular, the method is intended for use in the drilling of multiple short, lateral drainage holes originating in the main borehole and extending outward radially through the reservoir, at one or several depths. However, any hole, including the main borehole itself, can be created using this technique, depending on the lithology. This ability to make large multilateral conduits, at high speed, in underbalanced conditions, if desired, and with no drilling damage offers significant advantages for well construction and completion, particularly in hard carbonate reservoirs.
Unfortunately, coiled tubing is fundamentally ill-suited for use in drilling. The pipe is intrinsically weak and subject to fatigue, it cannot be rotated and it is difficult to apply substantial weight-on-bit. Coiled tubing drilling (CTD) involves "slide drilling" and this is why it is so different from conventional rotary drilling - the cuttings bed is not stirred-up by string rotation.
Coiled tubing drilling operations are today typically conducted using downhole motors (powered by mud circulation) connected to rotary drill bits. There have also been developments involving electrically powered downhole motors. Whether hydraulic or electric, these motors can deliver only limited torque to the bit, and it is not uncommon for these devices to stall-out. Furthermore, the coil itself must be protected from the torsional forces to minimise buckling. This makes penetration rates slow (20-40 ft/hr, often less), particularly in hard rocks like limestone and dolomite. At the same time, due to limited ID, circulation rates are low and cuttings transport in the annulus becomes a problem, particularly in horizontal and deviated holes. This necessitates frequent wiper trips to clear settled cuttings to avoid the coil becoming stuck. Apart from wasting time that could otherwise be spent drilling, these wiper trips also shorten string life by increasing fatigue (due to running pipe in and out of the well). In the event that coil does become stuck, it is difficult to retrieve due to limited overpull capacity and the risk of parting pipe.
Coiled tubing has been an invaluable tool to the oil and gas industry for some forty years. Each time that coiled tubing is rigged up and run into a well it carries with it a risk that the objective of that run will not be met. This paper analyses that risk based on some two years continuous records in the Asia Pacific Region and finds that the average rate of a successful run is 82% over a 23-month period. A database of about 1200 runs demonstrates the type, cause and frequency distribution of failures. Risk management options are reviewed and potential solutions offered.
The cause of failures is most frequently attributed to unknown well conditions. However, inadequate job planning, operator errors and equipment failures also have a significant contribution. The levels of technical complexity demands are escalating. In balance, there are increasing operational skill levels, equipment reliability improvements and a better focus on pre-job planning. This, then, tends to hold the status quo at a constant frequency over time. In order to increase the rate of success, lowering the difficulty of the jobs attempted and/or increasing the operating and equipment reliability will be required. Simplicity and reliability tend to go hand in hand. However, there is a general industry temptation to over-engineer and overcomplicate both the work scope and the equipment. The result may be viewed as unreliable and perhaps, not cost effective coiled tubing solutions.
The opportunity exists to significantly reduce the run failure count. This could be achieved by lowering ambitions and allowing equipment and skill levels to `catch up' with established industry coiled tubing solutions. It then raises the question "Is it better to do something simple well or to risk failure with technical ambition?" This paper concludes that the current failure rate can be improved upon with various corrective actions. This is essential in order to progress to further technical advancements.
For the past two years, data has been collected for each coiled tubing run into the well in a standardized format. The recordings include some basic well and coiled tubing pipe details along with a brief job description and outcome of the run, with appropriate comments. The scope of this paper only considers three of these parameters, namely the date, job type and outcome.
The first recorded run is 1st January 1999 and extends to the end of November 2000.
Eleven job categories have been used to identify job type. The majority of runs include one, or more, possible classification options such as "nitrogen assisted clean out" or "rotojet acid stimulation". In each case the dominant run objective has been used to classify the job type.
First, the paper gives a classification of the calculation models commonly used for the calculation of multiphase vertical pressure drops in oil wells. The main parameters of the experimental data used to develop the different empirical correlations are presented indicating the ranges where the correlations are expected to perform best. Next, an analysis and classification of the many possible causes of calculation error is given. Deviation of calculated and measured pressure drops is shown to stem from different sources that can have different importance from case to case.
The author collected and summarizes in the paper the findings of the many previously published investigations on the accuracy of the different pressure drop calculation models. A table including all available data on calculation accuracies is also presented. Statistical parameters of these investigations are shown to be widely scattered and to be of limited use to engineers seeking the most accurate model. Differences and contradictions in the results are evaluated and explained.
Finally, the author describes the petroleum engineer's proper attitude towards vertical pressure drop correlations. Practical implications of the proposed philosophy are also detailed. In conclusion, the paper provides the required insight and proper attitude to petroleum engineers facing the problem of predicting multiphase pressure drops in oil wells.
The steady-state simultaneous flow of petroleum liquids and gases in wells is a common occurrence in the petroleum industry. Oil wells normally produce a mixture of fluids and gases to the surface and phase conditions usually change along the flow path. At higher pressures, especially at the well bottom flow may be single-phase but going higher up in the well, the continuous decrease of pressure causes dissolved gas gradually evolve from the flowing liquid resulting in multiphase flow. Even gas wells can produce condensed liquids and/or formation water in addition to gas. These are some of the reasons why multiphase flow in wells is a frequently occurring and important phenomenon.
Multiphase flow is significantly more complex than single-phase flow. Single-phase flow problems are well defined and most often have analytical solutions developed over the years. Therefore, the most important task i.e. the calculation of pressure drop along the pipe can be solved with a high degree of calculation accuracy. This is far from being so if simultaneous flow of more than one phase takes place. The introduction of a second phase makes conditions difficult to predict due to several reasons. Friction losses, for example, are more difficult to describe since more than one phase is in contact with the pipe wall. In addition, due to the great difference in densities of the liquid and gas phases, slippage losses arise and contribute to the total pressure drop. Both of these losses vary with the spatial arrangement of the flowing phases (conventionally called flow patterns) in the pipe, etc.
Multiphase flow, though, is not restricted to flowing oil or gas wells. Gas lifting, an artificial lifting method, involves injection of high-pressure gas into the well at a specific depth making the flow in the well a multiphase one. Other lifting methods like the use of rod or centrifugal pumps also involve a multiphase mixture present in well tubing. It is easy to understand then that the proper description of multiphase flow phenomena is of prime importance for petroleum engineers working in the production of oil and gas wells. It is the pressure drop or the pressure traverse curve, which the main parameters of fluid lifting can be calculated with, and which forms the basis of any design or optimization of well production. Thus the accurate calculation of vertical two-phase pressure drops not only improves the engineering work, but plays a significant economic role in producing single wells and whole fields alike.
This paper discusses recent coiled tubing (CT) cement squeeze planning and operations conducted in the Casanare Field in Colombia. Zonal isolation for gas shutoff was identified as a critical factor to help reduce the GOR for wells that would otherwise shut in due to gas handling limits of the production facility. The planning phase included a cement laboratory audit that was used to identify the reason for discrepancies of the cement design between the laboratory conditions and the full scale mixing trial. Voltage variation during laboratory tests was identified as a major factor which affected the mixing energy. Another source of discrepancy between the laboratory results and the sample batches with field equipment was the amount of energy imparted to the system by use of centrifugal pumps. Cement design properties were critical to achieve sufficient thickening time and filter cake quality in the presence of relatively high reservoir temperature and reduced formation pressure. Discretionary disposal of several batches of cement was required until those design parameters were met. Communication and crew training were fundamental to identifying and resolving problems, especially in an area that had not yet conducted this type of operation.
Normal laboratory tests were conducted that included all standard measurements of thickening time, density, fluid loss and rheology as well as a comparison of sample batches mixed with field equipment. The tests were used to define the slurry to be used in the field. However when the initial 2 batches of cement were mixed on location, they were rejected because they were out of range for fluid loss and filter cake thickness and hardness. A target of 5 API units was used to obtain consistency needed to duplicate field conditions (Figure 1). Although the filter cake height curve begins to stabilize at 2.5 API units, the fluid loss volume does not begin to stabilize until approximately 4 API units have been reached. A laboratory audit was conducted to identify the nature of the problem. It was determined that laboratory mixing procedures only yielded an actual value of 0.5 API units due to problems with the local voltage supply during the slurry preparation (Table 1). The laboratory tests were performed again with the same amount of additives as the original blend (but with 5 API units mixing energy) and found the range of error created by the voltage discrepancy yielded a fluid loss of 92 ml/30 min (155% greater than the target value) and a filter cake of 2.28 inches (240% more than the target value). This is due to a minimum amount of shear energy needed by the slurry to properly activate the chemical reaction of the cement and additives.
The other problem identified was a discrepancy in the mixing energy as the result of using the centrifugal pump to circulate the slurry after it had reached the target density with all the cement additives. Use of the centrifugal pump on the mixed slurry for as little as 12 minutes was found to decrease the thickening time of the slurry from 7.3 hours to 4.0 hours. This variation of thickening time was determined to be independent of use of additives since it was repeated with the same results both with and without cement additives.
Buenos Aires Y-7
The first well planned for a cement squeeze, Buenos Aires Y-7 (Figure 2), was scheduled for conversion to gas injection with a workover and would limit the risk associated with the coiled tubing operations. During initial well preparation, two cement slurries were discarded on site because they did not meet field quality control guidelines for rheology or fluid loss. Operations were aborted to review the quality control problems including an audit of the cement laboratory that indicated the local electrical supply variation as a cause of the discrepancy. A new cement design was tested and verified with a trial blend using field equipment.