We present in this paper a reservoir analysis of the application of multilateral well technology in single-target structures. We focus on the correspondence between reservoir type and established multilateral well technologies. We consider a wide range of permeability fields and fluid characteristics, but consider only the depletion or solution-gas drive mechanism. We suggest that the behavior of multilateral wells under other drive mechanisms is fundamentally similar to that under the solution gas-drive mechanism. We conclude that with respect to the application of multilateral well technology, where the objective is attaining favorable production performance, there are essentially two classes of reservoirs - those that require maximum exposure to the wellbore and those that require limited exposure. The traditional unsealed multilateral technology (levels 1-4) is appropriate for the first class, while the recent sealed junction technology (levels 5-6) is appropriate for the second class. We explain precisely why that is so, and what criteria can be used to select the appropriate multilateral level within each reservoir class. We substantiate our conclusion by benchmarking the performance of multilateral wells with horizontal wells. Also we note that the correspondence between reservoir and multilateral technology types seems consistent with the economic feasibility of these solutions.
The successful implementation of horizontal drilling over the last two decades has led to the development of multilateral well technology. The number of multilateral well completions has increased substantially in the last several years due to advances in directional drilling and completions systems.1 Many field applications have been reported in the literature including compartmentalized reservoirs in UK2and Malaysia,3 stacked dual and triple, and fishbone laterals in Venezuela,4-5 and diverse applications in onshore and offshore USA and North Sea,6 Thailand and Brunei,7 Canada, Brazil, Italy,8 Nigeria,9 and the Middle East.10
The key driver in the application of multilateral technology has been exploitation of multi-target structures. These include compartmentalized, layered, and dispersed structures. The result is field development with fewer wells. On a per well basis this appears as accelerated production. The trade-off is reduced flexibility in reconciling production from potentially incongruous formations. Also, there may be greater risks in well failure due to unfavorable geomechanics.11-12
Application of multilateral technology in single-target structures has been thus far limited to naturally fractured reservoirs and heavy oil deposits. However, with the increasing number of subsea and deepwater developments, this technology is poised to become a common means for producing single-target structures, irrespective of crude type or other characteristics.
The objective of this study is to provide a firm foundation for this emerging class of applications. We take note of the latest developments in modeling wells of complex geometry13-16 and use recent numerical methods adapted to modeling these configurations.17-18
This paper describes the technical and legal problems have had in the design and construction of several projects in the oil and gas industry in Mexico and propose a methodology in order to avoid that.
Traditionally the people in charge of the projects have been people with a lot of experience in different areas of the company but the knowledge in legal and technical aspects of the projects is limited. These last two aspects are the key in the solution of the common problems.
The proposed methodology is based on the experience through 18 years in the design and construction of several oil and gas installations and it is complemented with the analysis of legal and technical regulations.
Traditionally the design and construction projects are taken for a single person who is in charge of all aspects of the project since conceptual engineering until the tests and start up of the plants this way to do the projects brings a lot problems due to a bottleneck in the definitions of the main aspects of the projects which depend on the leader of the project who has a lot of experience in several aspects of the technical area or administrative area so normally the leader can solve the problems related with his experience but normally there are a lot of aspects that require definition in time and form for the correct development of the project and the background of the leader is not enough to solve them and unfortunately the main team do not have the knowledge and experience to solve them so the problems will accumulate until someone take the decision in order to continue with the project (Fig. 1).
This traditional way to do the projects has a lot of opportunity areas such as:
Bottleneck in taking decisions
Delaying of engineering works
Delaying in construction program
Increase in engineering costs
Increase in construction costs
Deviation of original objectives
Additional projects for solution
Increase in total cost of the project
Deviations from the mid and long term plans
Legal problems for the people
Life Cycle of the Project
The different steps of the project involve several disciplines since needs detection until site remediation (Fig. 2) each one has particular importance in according with the objectives of the department involved but at the end the main responsibilities fall over the engineering and construction department due to this department must understand the planning objectives and must to know the strength and weakness of the operation and maintenance department in order to give the best solution for the project. If there is some misunderstand this can cause problems on the project execution and break all the planning programs. In order to avoid that is necessary to adopt a new way to do the projects and one of the main changes is to do Performance Contract for each one of the people that will participate in the project, which let him to know and understand the objectives in the short. Middle and long term and in case of deviations be able to take the correct solutions in form and time in this way the relation inside the asset must be clear for the people (Fig. 3) The premises to get it are:
Working to Known Standards
It is proposed a simple methodology to secure the satisfactory ending of the project, it is divided in two main areas: Technical and legal.
The Spraberry and Chicontepec fields are both giant oil fields contained within areally extensive, low porosity and low permeability submarine fan reservoirs. Each field has a gross interval of approximately 1,000-1,500 feet (300-450 m) with multiple reservoirs less than 10,000 feet (3,000 m) deep. Sand-prone intervals are laterally extensive and can be correlated regionally, but do have localized channeling. Both fields produce from solution-gas drive.
The Spraberry Trend Field, located in the Midland Basin of West Texas, was discovered in 1948. The field is estimated to contain over 10 billion barrels of original oil in place in a series of stacked Permian-age reservoirs covering over 2,500 square miles (6,475 sq. km). Cumulative production from the Spraberry is approximately 850 million barrels of oil and 3 trillion cubic feet of gas or approximately 8% of the original oil in place.
The Chicontepec Field, located in the Sierra Madre Oriental foothills in east-central Mexico, was first drilled in 1931. The field is estimated to contain 140 billion barrels of original oil in place and 35 trillion cubic feet of associated gas in a series of stacked Late Paleocene to Eocene-age reservoirs covering approximately 1,440 square miles (3,731 sq. km). Cumulative production from the Chicontepec Field is just over 140 million barrels of oil-equivalent or 0.1% of the original hydrocarbons in place.
However, the fields do differ significantly in their development history. Over 18,000 wells have produced some oil and gas from the Spraberry (over 10,000 currently producing) as compared to less than 1,000 in Chicontepec. Managing drilling costs, fracturing technology and controlling production costs along with economies of scale have allowed the Spraberry, once known as the world's largest uneconomic field, to be developed. Developing the Chicontepec field using similar methods would add significant reserves and production volumes for Mexico.
As we all know, finding new giant accumulations of oil and gas through exploration, especially in areas close to markets and existing infrastructure, is becoming increasingly difficult. An alternative is to look at previously discovered fields in these "mature" areas that are underdeveloped because of their historically low margin economics. Often through the use of new technology and by creative cost-cutting methods significant new production and reserves can be developed to more quickly meet consumer demand even without higher commodity prices.
This paper is a high-level comparison of two such fields; discussing the reservoir properties which have caused them to be deemed "uneconomic" and contrasting the development histories to suggest significant new reserves can be economically produced near-term from one that is underdeveloped.
The two fields are the Spraberry Trend Field located in the Midland Basin in West Texas and the Chicontepec Field located in east-central Mexico (Fig. 1). Both are located in mature producing regions where numerous other fields, including fields with significantly less original hydrocarbon in place, but with better reservoirs, have produced millions of barrels of oil and billions of cubic feet of gas.
A simulator has been developed to track two-phase slugs in pipelines transporting liquid and gas mixtures. The algorithm consists of close coupling of a one dimensional hydrodynamic slug flow model with an interface tracking methodology, and solving both simultaneously with an iterative procedure. The tracking scheme is based on propagating the fronts and backs of the liquid slugs to new locations during an incremental time step. New positions of the interfaces determine if a slug will enter the pipeline, exit the pipeline, collapse, merge with a slug ahead of it, or none of the above. The solution procedure determines the locations and the characteristics of all the slug units which exist in the pipeline at a given time.
Data collected in hilly-terrain and horizontal pipes in a large-scale multiphase flow loop were used to validate the slug tracking simulator. The average absolute percent errors in predicting the maximum slug length and inlet pressure were 12.6 and 0.47 respectively. A case study with field data collected on a 14,762 feet, 16 in. pipeline showed that the simulator predicted the maximum slug length and inlet pressure with absolute percent errors of 11.6 and 4.3 respectively. The comparisons are good and provide confidence in using the algorithm and the simulator to model and track two-phase slugs in hilly-terrain pipelines.
The simulator can be used to determine the characteristics of the slug unit used to design separators and slug catchers. It can also be used to analyze the impact of the flow and pressure transients on reservoirs, equipment, and structures, and study the effects of slugging on corrosion rates. The history of each slug in the pipe can be traced by determining if it will grow, shrink, collapse, or remain the same size as it traverses the pipe. During slug tracking, slug lengths are determined by the locations of interfaces instead of a correlation.
The efficient and economic production of hydrocarbon reserves found in reservoirs located in marginal fields and hostile environments often require the transportation of unprocessed fluids. In the case where the fluids are hydrocarbon gas, hydrocarbon liquid, and formation water, a multiphase flow mixture is the result.
A common occurrence in a pipeline transporting a multiphase flow mixture is the existence of flow patterns. These flow structures are characterized by a distribution of the interfaces separating the phases. Examples of flow patterns include churn, bubble, slug, and annular in vertical pipes; stratified, dispersed bubble, slug, and annular in horizontal multiphase flow. These flow structures are determined by, (i) operational variables, such as flow rates of fluids and pressure; (ii) geometrical variables, such as diameter and angle of inclination of pipe; and, (iii) physical properties of the fluids being transported, such as density and viscosity.
Flow variables in multiphase transportation are dependent on the distribution of the phases. These variables include liquid holdup, gas void fraction, pressure gradient, and heat and mass transfer coefficients. Thus, it is necessary to know not only when these flow patterns occur, but also the characteristics associated with each flow structure.
The slug structure is a common and complex two phase flow pattern. It consists of a region of liquid with entrained gases, referred to as the liquid slug body; a gas bubble or pocket, and a liquid film. Figure 1 shows the slug flow pattern in the case of horizontal flow.
In multiphase pipelines, slugs can be differentiated according to its mode of formation. The slug flow structure may be initiated by flow instabilities, such as the Kelvin-Helmholtz instability. These are termed hydrodynamic slugs. In other cases, the geometry of the pipeline plays an important role in slug formation. An example of this is a pipeline-riser pipe system. At low fluid flow rates, there is blockage at the base of the riser leading to an intermittent flow behavior termed severe slugging. Slugs formed as a result of the geometry are commonly referred to as terrain induced slugs.
We present results of modeling studies of injection schemes with wells using new completions technology, and address how these are applied or envisaged for the fulfillment of field development strategies in offshore environments.
A common theme in offshore developments is the use of fewer wells to achieve the production targets of the field. In mature fields, the limited availability of well slots is a severe constraint. In new developments, the drive is towards fewer and smaller platform installations. In subsea developments, particularly in deepwater, the objective is minimization of wellheads. There are clear financial, environmental, and technical reasons for these trends.
The use of advanced completions technology to reduce well requirements has been widely practiced in relation to production wells. Commingling of production in layered, compartmentalized, and dispersed geological settings has been achieved with multilateral wells, and conventional wells with flow control technology.1-4 The application of this technology to injection problems has received relatively little attention.5-6
The objective of this study is to analyze a number of injection problems that arise from actual field development scenarios. Four cases will be presented. The first two concern achieving proper partitioning of injected water into multi-zone structures. The third case concerns achieving the total target injection rate and partitioning. The fourth case concerns the alternating injection of water and gas.
This is a deepwater field, being developed by subsea wells. The structure consists of two partially overlapping formations of high permeability (3-5 Darcies), separated by non-reservoir rock. There is no external drive mechanism in the reservoir (e.g. an aquifer). Injection is to commence at initial production. Vertical injectors completed in both formations are to be used. The lower formation has about 1.5 times the injectivity of the upper formation because of its larger effective thickness. The objective is to inject into the upper and lower formations with a split of about 45% and 55% respectively, in line with the estimated distribution of reserves. The operator plans to install fixed and/or variable flow control devices in the injectors. The study analyzed injection options with and without valves. As Figure 1 shows, when no valves are used, the water will spontaneously partition between the two zones in the ratio of about 20% into the upper zone and 80% into the lower zone at relatively low injection rates. As the injection rate increases, so does the frictional pressure loss and this changes the ratio between the upper and lower zones to about 35% and 65%. This is shown in Figure 2. Note, however, that the fracture gradient of the formation imposes a constraint on the injection rate. Figure 3 shows that the desired partitioning can be achieved when both formations are equipped with variable flow control valves. By adjusting the valve apertures, the partitioning of the injectivity can be adjusted as reservoir conditions evolve.
This example concerns injection into three zones simultaneously, prompted by the limited number of well slots available on the platform from which this reservoir is being developed. In comparison to the previous example, there is greater contrast in the reservoir properties among the three zones, so that the middle zone has the highest injectivity index. The operator has initiated a water injection program for pressure maintenance, using vertical dual-string injection wells (two tubing strings), with the short string injecting into Zone A and the long string into Zones B and C. With this configuration, the approximate partitioning in injectivity is 25%, 50%, and 25% (Figure 4).
Caldera, J.A. (Schlumberger Oil Field Services) | Centeno, G. Tellez (PEMEX Exploracion y Produccion) | Robles, F. Cazares (PEMEX Exploracion y Produccion) | Sobrino, J.C. (Schlumberger Oil Field Services) | Frass, M.O. (Schlumberger Oil Field Services)
Most of the reservoirs in Mexico are carbonate formations, which produce mainly from high conductivity fractures, the temperature of these fields generally goes above 140 C. Under this combined scenario of fissures and hot environments low rate acid injection generates a very fast mass transfer from acid to the rock, which yields very poor results in terms of production. Good results have been obtained on latest designs when injection rates have gone above frac pressure. The high rate mitigates the combined effect of the high proportion of rock surface area in the fissure to low volume of acid in the rock and the high temperature.
Special acid systems as emulsified systems; organics acid and high strength acid have been used to complement this practice with excellent results. Gelled especial system has helped to obtain a homogenous distribution of the acid in the open intervals.
Deep and hot carbonate formations are very common in Mexico, temperature in this hot fields can reach above 150 C, depth of this limestones and dolomites productive reservoirs are often deeper than 5000 mts.
The most common operation in such fields is matrix-acidizing stimulation to improve well production.
High temperature and heterogeneous distribution of rock properties are the main limitation that the operator has to face to obtain positive results after acidizing treatment.
Generally it is believed that this reservoirs are naturally fractured with a very permeable and well connected network of fissures, however some times log response and transient test interpretation yields a different reservoir characterization where one or several fractures are the only mean of production in the whole reservoir thickness.
Production models were used to match production history to verify that reservoir characterization from transient test is suitable and representative of these fissured wells.
Based on this, a question arises in reference to what should be the stimulation strategy under this combined scenario of high temperature and fissured wells.
The effectiveness of the acid is not the same under matrix injection into a one porosity medium than placing acid inside a hot fissure.
This work presents a documentation of latest experiences where a multidisciplinary approach has helped to introduce reservoir characterization in the stimulation design.
Naturally Fractured Reservoirs
Typical double porosity response is not always seen on pressure transient test on fissured formations, the lambda and omega shaped curves will only appear un certain conditions of matrix permeability and fractures distribution, homogeneous and unfractured response could be observed if matrix permeability is equal or higher than fracture permeability or if the matrix has no permeability and the fractures are oriented in several directions. Linear flow can be observed if the matrix has no permeability and the main fissures are oriented in one particular direction.
When linear flow is observed, a transient test allows characterizing those fractures. Fracture length and conductivity can be calculated and used in production modeling to match actual production data.
Well A test shows linear flow with a 61 feet long fissure matched with an infinite conductivity fracture model (Fig. 1), fracture length and conductivity obtained from transient test could be used to calculate the theoretical production response of the well, matching the actual production data (554 bpd with Pwf: 4100 psia) (Fig. 2).
In the summer of 2000, Conoco began a program to develop a series of shallow, low-pressure gas reservoirs in the Indonesian waters of the West Natuna Sea. The project consists of a series of subsea wells linked by pipeline to a central mobile gas processing and compression unit which feeds a sales line to Singapore. Overall project life is 20 years and will require development of 8 small fields with reserves of the order of 1 TSCF gas.
Initial project planning used conventional well designs to deliver rates of the order of 20 MMSCFD/well from a number of gas reservoirs. This type of well productivity required 10 wells to meet Conoco Indonesia's maximum contract supply rate with several wells allocated to each reservoir. To improve project economics, a reduced well count employing high performance completion designs was developed. The high performance completions were designed to provide flow rates of the order of 100 MMSCFD at initial reservoir pressures ranging from 1250 psi to 1900 psi. These flow rates allowed well counts to be reduced to one well per reservoir.
This paper will review Conoco's methodology for design and implementation of the first 4 high performance completions in the West Natuna Sea Gas Project. Well deliverability and initial project results will be discussed.
Conoco, through its Indonesian subsidiary Conoco Indonesia Inc. (CII), has explored the Indonesian waters of the West Natuna Sea for over 30 years. As shown in Figure-1, Conoco's West Natuna Sea Production Sharing Contract (PSC) Area is located approximately 200 miles north/northeast of Singapore near the Indonesian/Malaysian border. During its period of operation the Company has discovered and developed several significant oil fields in the Block-B Production Sharing Contract Area as shown in Figure-2. The Company has also discovered a number of gas fields in the Block-B PSC Area, however, the lack of a local gas market and gas pipeline system has prevented effective development of these fields. Similarly, associated gas produced with oilfield crude has not been economically transported and sold and as a result produced gas volumes in excess of fuel requirements have been flared. As shown in Figure-3, Conoco's gas discoveries and associated gas resources in Block-B have been effectively stranded by lack of a gas pipeline system and local gas market. Adjacent PSC operators have also experienced these types of problems and have suffered significant stranded gas volumes.
In the late-1990s Conoco worked with the Indonesian State Oil Company, Pertamina, and adjacent PSC operators Gulf Canada and Premier Oil to establish a 20-year gas supply contract with Singapore and a gas pipeline from the Indonesian West Natuna Sea to Singapore. An overview of the pipeline system and the various PSC areas is shown in Figure-4. Under the terms of the gas supply contract, the three PSC operators agreed to supply approximately 2.5 TSCF of gas at an average rate of 325 MMSCFD for a long-term electrical power generation project. Each operator is responsible for developing gas fields or associated gas in its own PSC area to meet its share of the total production requirement. Each operator's gas is then metered and flowed to the jointly owned and operated West Natuna Gas Transportation System for transport to Singapore and sale to the purchaser.
This paper presents a methodology for the optimal hydraulic fracture treatment design. The methodology includes, the construction of a "fast surrogate" of an objective function whose evaluation involves the execution of a time-consuming computational model, based on neural networks, DACE modeling, and adaptive sampling. Using adaptive sampling, promising areas are searched considering the information provided by the surrogate model and the expected value of the errors.
The proposed methodology provides a global optimization method, hence avoiding the potential problem of convergence to a local minimum in the objective function exhibited by the commonly Gauss-Newton methods. Furthermore, it exhibits an affordable computational cost, is amenable to parallel processing, and is expected to outperform other general purpose global optimization methods such as, simulated annealing, and genetic algorithms.
The methodology is evaluated using two case studies corresponding to formations differing in rock and fluid properties, and geometry parameters. From the results, it is concluded that the methodology can be used effectively and efficiently for the optimal design of hydraulic fracture treatments.
Hydraulic fracturing is one of the most common stimulation strategies used to enhance the production from oil and gas wells. During a hydraulic fracturing treatment, fluids are injected to the formation at a pressure high enough to cause tensile failure of the rock, and propagate the fracture. As a result of a successful treatment, a path with much higher permeability than the surrounding formation is created from the well. Each of the fluids injected during the treatment execution performs a significant and specific task. The initial fluid, known as pad, initiates and propagates the fracture. The following stages of the treatment involve the injection of a fracturing fluid with varying concentrations of proppant. The fluid is intended to continue the fracture propagation and the proppant will keep the fracture open, even though the formation stresses will try to close the fracture, after the fluid injection ceases.
For a given formation, the design of a hydraulic fracture treatment involves the selection of appropriate fracturing fluids and proppants, the number of treatment stages, the concentrations and the rates and pressures of injection of each stage. Each design will result in a specific fracture geometry and conductivity, which is related to the production increase obtained from the fractured well. This means that, due to the several possible combinations of the parameters involved, and their non-linear interactions, there are a significant number of possible fracture geometries, each of which will result in a different post-fracture well production performance.
Ralph and Veatch1 presents the general concepts of hydraulic fracture treatments economics and introduced the net present value as a valuable tool for the optimal design of hydraulic fracture treatment. An optimal hydraulic fracture treatment design maximizes the net present value of the revenue after the treatment, considering the post-fracture production performance and the treatment costs.
A theoretical and experimental study on electric resistivity of vuggy fractured media is presented. In order to have a rigorous control of the involved variables, a vuggy fractured medium is idealized by a cubic array of cubes having hemispherical cavities drilled in each cube face. In this model, the spaces between the cubes represent fractures and the hemispherical cavities represent vugs. The theoretical developments lead to a simple relationship expressing formation resistivity factor as the product of two factors, one depending on vug porosity and the other on fracture porosity. This formulation has been validated with experimental data obtained with a special resistivity cell. The proposed formulation can easily be generalized to be applicable to real rocks, and so it is a useful tool for interpretation of electric well logs of vuggy fractured formations.
It is well known that an important part of the world oil production comes from vuggy fractured reservoirs. This type of reservoirs are commonly found in Saudi Arabia, Iran, Iraq, Mexico, Oman and Syria, hence the importance of developing reliable analytical formulations concerning the geometrical properties, storage capacity, and flow properties of the porous space. A practical way of knowing the internal geometry of a porous medium consists in using the so called formation resistivity factor.1 By knowing the formation resistivity factor, it is possible to determine, for instance, the magnitude and type of porosity, and the tortuosity. However, in the case of vuggy fractured media, no previous well established expressions relating formation resistivity factor and the various kinds of porosities have been proposed to date.
In this paper, expressions for the formation resistivity factor of vuggy fractured media are developed in terms of fracture and vug porosities. To establish these formulations, the vuggy fractured medium is idealized by a cubic array of cubes with hemispherical cavities drilled in each face. In this model, the spaces between the cubes represent fractures, and the hemispherical cavities represent vugs.2
The theoretical work is based on the idea that, in a vuggy fractured medium saturated with a conducting fluid, the vugs are zones of very low resistivity (or very high conductivity) in comparison with that of the fractures. In this way, one arrives at an equation expressing formation resistivity factor as the product of two components, one depending exclusively on fracture porosity, and the other on vug porosity. This equation was validated with experimental data obtained with a special resistivity cell.
The Fractured Medium
Due to the geometrical complexity of a vuggy fractured medium, a rigorous analytical study of the formation resistivity factor is not an easy task; however, by making certain logical idealizations it is possible to manage this problem in a relatively simple way. But before entering the study of vuggy fractured media, the case containing no vugs will be considered in this section.
The simple fractured medium (i.e., with no vugs), has previously been treated analytically by several authors. For its study, the following basic considerations are made: (1) When a potential difference is applied across the medium saturated with a conducting fluid, the electric current flows much more easily through the fractures than through de matrix, so that the current through the matrix can be considered as negligible, and (2) the fractured medium can be idealized by a cubic array of cubes (Warren and Root model3), as shown in Fig. 1. This same model has been used by Towle4 and by Aguilera5 for studying the relationship that exists between porosity and formation resistivity factor of fractured media.
Hole quality is generally related to the "smoothness" of the wellbore or, sometimes, to wellbore stability. This paper will demonstrate that wellbore spiraling is the primary contributor to poor hole quality and that almost every well contains some degree of spiraling unless specific actions are taken to prevent it. Hole spiraling was first studied by Lubinski et al. in the 1950's, and they described it as a "crooked hole." Although the symptoms have been well recognized in the industry, only recently has a solution been proposed and tried specifically to cure hole spiraling. To implement the concept, two new drilling systems (a steerable motor and a rotary steerable) have been developed. Field data indicate that generating a straighter, high-quality wellbore has improved almost every aspect of drilling. These improvements include lower vibration, better bit life, fewer tool failures, faster drilling, better hole cleaning, lower torque and drag, better logging tool response, and better casing and cement jobs. Several case studies will be discussed to demonstrate the positive economic impact of producing a high-quality wellbore.
Hole quality can have a profound effect on the total well construction time and cost and sometimes even determine the success of drilling a well. The importance of good borehole quality increases as extended-reach and offshore wells become more common, as they have in recent years.1,2 While some hole problems are a function of wellbore stability and must be addressed with proper mud weight, others arise as a result of poor wellbore geometry. For example, how accurately does the borehole itself follow the surveyed path? Does it follow a more or less helical path around the centerline of the planned well trajectory like a spiral? Poor wellbore geometry is an area that is often overlooked, but it is important that the following questions be addressed: Is hole spiraling prevalent? And, if it is, why haven't we known it?
Hole spiraling is not easy to detect because MWD surveys are usually at least 30 ft apart. Because the collars will lie on the low side of the wellbore, the survey data would show very little trajectory variation. However, a sinusoidal form of borehole can be clearly seen by a wireline imaging log (see Fig. 1) or the formation evaluation logging tool data (see Fig. 2). Nieto et al.3 report that it is quite common to see borehole-induced "sinusoidal" noise on logging tools, especially those relying on contact or proximity to the wellbore wall.
Some pieces of data would indicate that spiraling is prevalent in many wells. One is a study4 that showed that wells drilled with a new steerable drilling system produced friction factors significantly lower than conventional steerable systems. In some cases the friction factors in open hole and in casing were the same. The authors are not aware of any wells ever drilled that have achieved friction factors as low as these are. This new steerable drilling system employs extended-gauge bits and specially designed mud motors with pin-down connections. This system is run according to proprietary methods to ensure consistent results over many wells. The system is designed to eliminate spiraling, and there is powerful evidence that it does. The fact that low friction factors are unique to wells drilled using this system suggests that most wells drilled conventionally are spiraled to some degree.
Another indication that wells are spiraled in general is the fact that a drill-string is a long slender rod with a bit on the end. Although many directional assemblies have some stabilization that tends to keep the bit closer to center, this stabilization is usually several feet behind the bit, allowing it to wander off center. By comparison, a standard drill bit made for drilling wood or metal has several multiples of the diameter worth of non-cutting gauge protection in the form of helical flutes. For example, a 1/2-in. bit has roughly 3-4 inches of "full-gauge" fluting.