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Abstract Completion scenarios and knowledge of formation damage distribution are key factors that determine the success of horizontal well applications. In a bottomwater drive reservoir the completion scenario should be selective because a significant portion of the horizontal well section would not be productive at late production period. A simple correlation to estimate pseudoskin factors due to partial completion for a horizontal well is provided. When water or gas coning is not expected, distributed perforation intervals in a damaged formation yield the highest productivity. Introduction Horizontal wells become popular in the last decade for exploiting more oil from the reservoirs. The applications range from extracting attic oil and ultra-thin oil column to developing a marginal oil field. There are of course many other horizontal well applications for improving productivity of various reservoirs. As the technology is relatively new, the reservoir fluids flow behavior is not fully understood. Many researchers have devoted their efforts to come up with results which undoubtedly contribute to both practical consideration and the actual operations. It is the facts, however, that some of horizontal wells already implemented were not as good as expected in their performance. There might be situation beyond expectations that caused the implementation technically and/or economically unsuccessful. Probably, poor reservoir description including geology and fluids distribution and formation damage due to drilling and completion fluids have resulted in poor performance. Refs. 8 and 9 provide guides in terms of interdisciplinary concepts for horizontal well applications. Complex mechanism of fluids flow in a reservoir system producing the fluids through a horizontal and in the wellbore itself have been challenging to researchers in petroleum industry. Many studies have been focused on the wellbore hydraulics. The implication is that if the pressure losses in the wellbore is greater than ten percents of the drawdown then the inflow performance may be considerably affected. Most of these efforts, however, involved single phase flow in the reservoir, assuming the same specific productivity index at any point along the wellbore. Several papers dealt with wellbore/reservoir interactions for two-phase flow situations. Other researchers emphasized their works on inflow performance relationships (IPRs)for solution gas drive horizontal wells. Unlike for vertical wells, no attempt has been made to generate damaged and stimulated dimensionless IPR curves for horizontal wells.
- North America > United States > Texas (1.00)
- Asia (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (24 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
Abstract This paper describes the results of formation damage study on first horizontal well drilled and completed in Croatia. The specific problem of formation damage caused by polymer mud was evaluated in the laboratory, investigating the rock-fluid compatibility and methods for restoring the reservoir permeability around the wellbore. The source of damage was identified as a vey tough mud filtrate cake as well as the reduction of permeability inside the pore space due to mud filtrate invasion. The two stages well stimulating procedure for damage removal, consisting of soaking and injecting oxidizer, then acid, in two steps, tested in the laboratory, showed promising results. Introduction In the last decade the technology of horizontal wells, because of their enhanced productivity, has become widespread. More than 2000 horizontal wells are completed each year worldwide. Maintaining maximum deliverability from these wells requires that formation damage be minimized. In turn, minimizing or preventing formation damage, which is either created during drilling or removed during well completion and production, requires serious in-depth research. Horizontal wells are usually completed by either setting the predrilled or slotted uncemented liner, or leaving the horizontal section as an open hole. In both cases the production interval is not perforated. This means that the horizontal well lacks the perforation tunnels that are normal used in conventional vertical wells to bypass part of the damage caused by drilling mud invasion. Mud damage, which adversely affects productivity, occurs as a result of several factors. First, in open hole, the filter cake, can be formed both as external and uniform at the formation face and as internal, inside the porous medium around the wellbore. Another problem is the permeability reduction that occurs because of the interaction between the rock and incompatible mud filtrate that penetrates into the vicinity of the wellbore. These two factors, often combined with the heterogeneity of the payzone compound the risk of impaired productivity in horizontal wells. Very often for horizontal wells, the water base polymer-type systems are used as drilling fluids. By their nature, polymers contained in the filter cake are tough and not easy degradable. Moreover, the complexities involved in the study of mud filtrate and rock interactions necessitate more detailed research to identify and control the formation damage in horizontal wells. The most optimistic approaches to this problem are to select of mud system that is as unintrusive as possible, or, because a damage is practically inevitable, to implement a proper damage removal, well stimulation method. Well treatment may include filter cake clean up (using drawdown pressure to initialize production, and/or application of a chemical breaker system to destabilize and remove the filter cake) and/or chemical stimulation targeted toward mud filtrate damage elimination. The findings that relate to problems of productivity impairment due to formation damage of the first horizontal well drilled and completed in Croatia are described in this paper. Case History Well A has been designed as a high rate gas-condensate producer and was drilled into the reservoir inside the already developed field, located in the southern part of Pannonian Basin - the Sava Depression. The well parameters are shown in Table 1. The targeted reservoir was at an average depth of 2400 m (TVD), and has an effective thickness of 29 m. The gas-bearing rock is low to medium compact sandstone (mineral composition is shown in Table 2). According to lithological data from surrounding wells, the reservoir lithology is characterized as laminated sandstone intersected with shale layers, which indicated petrophysical anisotropy as a result of complex sedimentary genesis. After completion, before bringing the well onto production, the slotted liner was briefly cleaned up with 2% HCl through 2 3/8 in. tubing lowered to 2890 m in an attempt to disintegrate and remove the mud filter cake.
- Geology > Mineral > Silicate (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.56)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.45)
Abstract Since matrix acidizing is a low-budget stimulation operation, there has been little incentive to improve acidizing treatments including real-time technology, despite the wide usage of matrix stimulation. Hence, for matrix acidizing real-time quality control, job monitoring and job optimization is seldom practiced and nosophisticated tools were available. However, the ever increasing length of stimulated segments and the associated technical and economical problems in combination with reports on high stimulation failure rates have created an emphasis on the development of real-time tools, not only for monitoring and analyzing acidizing treatment efficiency but also for evaluating pre- and post-treatment job performance. All the tools available today use the evolution in skin factor as a quantitative measure of the overall treatment. For the calculation of the skin factor three methods, based on measuring the injection rate and pressure, are presented. The methods differ widely, from applying a steady-state approach to the fully transient flow regime accounting for various effects influencing the pressure response. Comparisons are presented, based on detailed analysis of the models' features and matching of field data. An obvious conclusion is that the fully transient method is the most promising means of real-time monitoring and analysis of matrix treatments for the future. Introduction Matrix acidizing is a stimulation technique involving the injection of an acid solution at pressures below the parting pressure of the formation. The acid dissolves some of the minerals present in the near-wellbore vicinity and hence original permeability is recovered (in sandstones) or enhanced (in carbonate formations). When compared to other oilfield operations such as hydraulic fracturing, significant failure rates were reported for matrix stimulation applications, i.e. the technical and economical objectives are not reached. Since in previous times acid treatments were regarded as relatively cheap operations, few efforts to improve acidizing technology were undertaken. However, the industry's attitude towards matrix acidizing has recently changed due to the ever increasing length of wells to be stimulated, as a result of evolving horizontal well technology, and the associated logistic, operational and economic problems involved. This situation promotes focused efforts for the development of new acidizing tools and technology such as the red-time techniques discussed in this paper.
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract The paper will review the most recent experience with completion techniques and production performance in horizontal wells in the Statfjord field. A total of 25 horizontal/extended reach wells have been drilled and completed to date. Wells with horizontal section up to 2250 m have been drilled and the longest horizontal displacement is 7290 m. Several well interventions have been performed in these wells, primarily for re-completion purposes. The paper will describe development of completion and intervention techniques with focus on perforating, well killing, well productivity and sand free production rates. Operational consequences in well interventions due to well design will be shown. The first horizontal wells were perforated in overbalance on drillpipe, while today most intervals are perforated in underbalance with coiled tubing. Production and reservoir management for these wells will be discussed with focus on requirements for data acquisition and well intervention. Future possibilities for horizontal wells on Statfjord and technology requirements will finally be discussed in the paper. Introduction The Statfjord field is located in the North sea on the Norwegian-UK boundary line. Three filly integrated production platforms with a total oil processing capacity of 132 000 Sm/d have been installed for the field development. Each platform has two drilling shafts and a total of 42 well slots. A total of 124wells have been drilled to date, including 10 redrills. The field is one of the largest offshore fields in the world and had an average plateau production of 110โ120.000 Sm/d. Total oil reserves are estimated to be 620 ร 10 6 Sm. The field has been on declining production since 1993 and to date almost 80% of the recoverable reserves have been produced. The structural elements of the Statfjord field could, very simplified, be described as a row of several major fault blocks dipping to the west by 5 to 8 degrees. From the top of the structure and eastwards, the reservoirs are broken apart by a complex pattern of listric faults. (figure 1 & 1B). The main oil-producing reservoirs of the field are sandstones of the middle Jurassic Brent Group and the Lower Jurassic/Upper Triassic Statfjord formation. The Brent Group is divided into the Upper(Tarbert and Ness) and Lower (Etive, Rannoch and Broom) Brent formations. The Statfjord reservoir is divided into three producing formations, from the top Nansen, Erikson and Raude.
- Europe > United Kingdom > North Sea > Northern North Sea (1.00)
- Europe > Norway > North Sea > Northern North Sea (1.00)
- Phanerozoic > Mesozoic > Triassic (0.54)
- Phanerozoic > Mesozoic > Jurassic (0.54)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Statfjord Group (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Cook Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Brent Group (0.99)
- (5 more...)
Abstract Two of the most important recent developments in petroleum production are horizontal wells and high-permeability fracturing. This work combines them with potentially considerable incremental production economics. Hydraulic fractures have a distinctly defined azimuth, in almost all cases of interest; they are vertical and normal to the minimum horizontal stress direction. Horizontal wells can thus be drilled either normal or longitudinal to the fracture azimuth. The first configuration has been already considered in the literature and in practice, and is applicable for relatively low-permeability formations. The emergence of high-permeability fracturing, also patently successful in a number of fields, often results in low dimensionless conductivity hydraulic fractures. The possibility of fracturing horizontal wells longitudinally may have the net effect of installing a high-conductivity streak in an otherwise limited conductivity flow conduit. A rigorous model was constructed to describe this configuration. This paper presents comparative production rates and cumulative productions for longitudinally fractured horizontal wells vis a vis vertical fractured wells and unfractured horizontal wells. The range of attractiveness of the individual options is presented in the framework of discounted revenues. Introduction Horizontal wells and high-permeability fracturing are perhaps the most important recent development in petroleum engineering. The productivity index of a horizontal well has been well studied in the literature. The issue of areal permeability anisotropy and its economic impact have also been considered. Hydraulic fractures are, in almost all cases of interest, vertical and normal to the minimum horizontal stress diction. Horizontal wells can thus be drilled either normal or longitudinal to the fracture azimuth. The first configuration results in transverse fractures and has been found to be applicable for relatively low-permeability formations. For the case of transverse hydraulic fractures a skin effect, introduced by Mukherjee and Economides, accounts for the extra pressure drop when fluid converges from linear to radial flow within the fracture. This calculation points to a substantial reduction in the performance of such transverse fractures, compared to the performance from a fracture completed from a vertical well. There is much less information available on the other configuration, involving longitudinally fractured horizontal wells.
Abstract Formation damage around horizontal wells can result in poor performance and failure of these wells. The objective of this paper is to present a newsolution for transient pressure behavior of horizontal well injectors and/orproducers in injection processes. Equations for productivity and injectivity of horizontal wells during injection processes are introduced that are based on the effective horizontal well length contributing to unimpaired injection or production. Effective horizontal well length in steady state reservoirs is the well length with zero skin factor that will yield the same steady state productivity or injectivity index as the one obtained with actual drilled horizontal section length with skin factor. A relationship between mechanical skin factor and effective horizontal well length is derived and explained. Guidelines for analyzing transient testing of horizontal well injectors for determination of reservoir permeability, skin factor, and effective length are presented. It was found that flow efficiency is the ratio of steady state shape factor evaluated at actual length of the horizontal section and the one evaluated at effective length. Furthermore, flow efficiency is always greater than the fraction of horizontal well contributing to unimpaired production or injection. This indicates that a decrease in effective length is not equal to the loss in injectivity or productivity of the horizontal well, thus implying tolerance for formation damage around these wells to a certain degree. Formation Damage Around Horizontal Wells Flow surveys in vertical wells have shown that a high percentage of the zone open to the wellbore is not contributing to the total flow as a result of formation damage created during various stages of oil and gas well drilling, completion, stimulation, production, and improved oil recovery operations. Drilling and completion fluids are believed to cause the initial damage. Stimulation treatment may not yield the expected productivity increase, as predicted by model studies, due to introduction of additional damage by the stimulation fluids. Damage caused during the production phase by various processes such as sandfines migration and asphaltene/paraffin deposition can severely restrict fluid movement into the wellbore. Analogous to productivity decrease of production wells is the injectivity decrease of injection wells as a result of formation damage.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Abstract The placement of acid over the entire wellbore interval can be the key to successful stimulation treatments in wells with long (often horizontal) completion intervals. This paper discusses computer simulations performed to determine how fluids are distributed in the wellbore during bullheaded and circulated acidizing treatments. One of the novel aspects of these stimulations is the inclusion of wellbore effects arising from the transient flow of acid and diverter along the wellbore. The results give an insight into a possible cause of some of the poor stimulation performances observed in the field when typical volumes of low-viscosity acids were injected without diversion or selective-placement techniques. Such situations can result in the acid coming into contact with only a small fraction of the treatment interval. The simulations also show how viscosifying the acid could have improved the stimulation performance. This paper outlines the basic concepts of the simulations and some of the general trends observed from the results. In particular, the inclusion of transient wellbore flow calls for the modification of recently published guidelines for various diversion techniques. Introduction Horizontal wells are widely recognized to have advantages over vertical wells. They are popularly used, for example, to exploit thin oil-rim reservoirs, to avoid such drawdown-related problems as water/gas coning and sand production, and to extend wells by means of multiple drainholes. Yet their potential productivity improvement factors often fail to materialize in practice as a result of the skin (permeability-impairing near-wellbore damage) caused by drilling and completing the wells. Recent investigations have shown that skin can be as detrimental to the performance of horizontal wells as it is to that of vertical wells. In fact, horizontal wells often experience higher skin values than conventional wells, as a result of the slotted liners or barefoot completions that are employed in such wells. Unlike the earlier industry standard of cased and cemented completions, these horizontal-well completions lack perforations. Field and laboratory experience has shown perforations to be an effective means of bypassing the impaired zone. For that reason the avoidance of near-wellbore permeability impairment, e.g., through the use of new drilling fluids and under-balanced drilling and completion, has been emphasized in the drilling of openhole horizontal wells. A significant research effort over the last few years has also involved the experimental determination of the best clean-up procedures to follow prior to production. This interest in wellbore cleaning has led to a resurgence of matrix acidizing, which over the years has proven to be a cost-effective method of removing impairment in the near-wellbore area of vertical wells. The stimulation of horizontal wells by means of matrix acidizing, however, has often met with limited success.
- North America > United States > Louisiana (0.28)
- North America > United States > Texas (0.28)
Abstract This paper examines some mechanical aspects of formation damage as they apply uniquely to horizontal wells. First a seldom recognized phenomenon of mechanical damage due to drill string rotation is presented along with a method for estimating the extent of the damaged area. Next, the invaded zone is examined in some simple examples to ascertain qualitatively the geometry of the invaded zone due to varying exposure times of different parts of the horizontal section during drilling. The relative time scales between exposing new hole with the drill bit, the invasion rates into the formation, as well as the changing differential pressure in the horizontal annulus are incorporated into a simple model to determine the effect of changing annular pressure while drilling. Finally an inexpensive means of mechanically achieving zone isolation for damage removal treatments in unconsolidated zones is presented. Introduction Horizontal wells are unique in many respects. What has become intuitive in our thinking regarding vertical wells may lead to wrong thinking in horizontal wells. We have examined two mechanical aspects of formation damage here. One has received little or no attention in the literature, and that is the damage caused by the drill string rotating and sliding in a horizontal well. We will derive a method for estimating the extent of this damage under quasistatic conditions. The second phenomenon we examine is the geometry of the invaded zone during typical drilling operations. Frick and Economides have shown the zone to be a right circular cone for a homogeneous formation with a larger radius at the near portion (heel) of the horizontal section and a smaller radius at the far end (toe). Because a number of operators have observed greater production from the heel, contrary to what one might expect, it appeared worth examining in more detail the effects of varying drilling rates and realistic circulating modes to determine their effect on the geometry of the invaded zone in a homogeneous reservoir. What is now becoming most obvious for operators of horizontal wells is that many reservoirs are quite heterogeneous, and that damage removal and effective reservoir management in horizontal wells is not going to be accomplished without some means of zone isolation. The initial cost of conventional zone isolation in any horizontal well is quite high and there is a natural reluctance to commit to such a high initial completion cost. We describe later in this paper a less expensive alternative to conventional zone isolation for application in unconsolidated sands.
- Europe > United Kingdom (0.89)
- Asia > Indonesia (0.89)
Abstract The productivity of wells with non-perforated completions can be impaired by both mud filtrate invasion and incomplete mud filter cake removal. Well inflow modelling illustrates that the percentage of the interval flowing and the distribution of the flowing intervals, are more important than the filtrate induced permeability reduction around the wellbore. Therefore adequate filter cake removal is essential for optimum well performance. This paper addresses both physical and chemical methods of mud filter cake removal. Introduction The use of high angle and horizontal wells is increasingly widespread, primarily because of the increased productivity they provide. Many of these wells employ non-perforated completions and both mud filtrate induced formation damage and the incomplete removal of mud filter cake along the entire open hole section can impair productivity. This paper uses the results of inflow performance modelling to demonstrate the relative importance of each of these causes of productivity impairment. Field evidence of impaired productivity was highlighted in an internal company review of the performance of recent BP operated horizontal wells in the North Sea. Several of these wells did not produce from the entire completed interval. Geological variation and partial clean-up of the drilling mud filter cake are believed to be the two main reasons for reduced production. Specially designed filter cakes which only need low differential pressures to lift off, or which can be readily removed by washing fluids, can maximise productivity from horizontal or high angle wellbore sections. This paper presents the results of laboratory work which demonstrates that the differential pressure required to initiate flow through filter cakes is a function of both mud type and formulation. In addition formation characteristics can impact upon filter cake removal success. Laboratory results show that when chemical washing fluids are used, they must be tailored to the mud filter cake that is to be attacked. WELL INFLOW MODELLING Modelling of inflow performance has been used to assess the relative importance of damage from mud filtrate invasion and incomplete filter cake removal. Several methods are available for the modelling of high angle and horizontal wells. The method of Goode and Wilkinson has been used because it allows flow from discrete sections of a horizontal well to be modelled. The impact of near-wellbore permeability reduction on the flow efficiency (see Appendix A) of a horizontal well is shown in Figure 1 (Well details are given in Appendix B). Figure 1 shows that a small reduction in the near-wellbore permeability will have only a small impact on the flow efficiency of a horizontal well. If, however, the permeability reduction is in excess of 70% then the productivity of the well falls significantly. P. 125^
SPE Members Abstract In previous publications we have introduced methods for the matrix stimulation of horizontal wells, damage characterization and removal, and economic criteria for the evaluation of the job effectiveness. The characteristic shape of damage, which is neither radial nor evenly distributed along a horizontal well, would impact the effectiveness of a matrix stimulation treatment. Full removal of damage is probably never practical because of thief zones and a marked inability to divert the stimulation fluids. Also, the large volume of acid to be injected in horizontal wells will likely create significant corrosion problems. Therefore, partial stimulation and perhaps partial completion, by deliberately leaving segments of the horizontal well unperforated, should be contemplated. By balancing the expected well performance against the fluid volumetric coverage and the length of the open segments, the optimum stimulation and completion design can be evaluated. The net present value (NPV) is used u the optimization criterion. In this paper a cue study of a 1600-ft horizontal well in a 160-acre drainage area in a sandstone reservoir is presented. Based on expressions for original and posttreatment skin effects, which are presented in explicit form, an economic evaluation of several stimulation and completion design options is carried out. A general recommendation on the proper matrix stimulation in horizontal wells is derived based on the results of this cue study. Introduction Horizontal wells, frequently spanning several thousand feet are likely to be damaged and in need of stimulation. Causes of less than expected performance from horizontal wells include inappropriate reservoir selection (thick formation with low vertical permeability) wrong well trajectory (e.g., normal to the minimum permeability) and, especially, unstimulated damaged wells. Frick and Economides have presented analytical expressions for the skin effect of a horizontal well. This skin effect characterizes the shape of damage which is likely to be in the form of a truncated elliptical cone with the larger base near the vertical well section. The aspect ratio of the ellipse depends on the vertical to horizontal permeability anisotropy. The same authors also presented analytical expressions for the posttreatment skin effect. In the cue of sandstones the posttreatment skin effect. In the cue of sandstones the stimulated zone was presumed to be of the same general shape u the damage zone. For carbonates, where stimulation depends more on reaction kinetics and less on flow through the porous medium, the stimulated zone was assumed to be cylindrical, although this assumption is currently under scrutiny. Bullheading stimulation fluids into a horizontal section is unlikely to be a successful stimulation treatment since much of the fluid would be spent laterally, where damage has been removed and the impediment to flow has been reduced. Therefore, diversion, such u chemical or mechanical (provided by coiled tubing) or both has been proposed and is in use in the industry. A semianalytical solution of the performance of a partially completed horizontal well has suggested that a large portion of the theoretical open-hole undamaged flowrate can be realized with several perforated segments that are separated by unperforated intervals. This is a particularly useful finding because completion and stimulation become the object of optimization and, in practical terms, allow a variety of option in the hands of an operator. One extreme would be the full removal of damage along the entire well trajectory. P. 351
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion (1.00)
- Reservoir Description and Dynamics (1.00)