|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Drillout optimization is analyzed based on criteria that includes higher rate of penetration (ROP), reduced overall cost per foot, reduced drilling time, and reduced wear rates. In the industry, there are no mechanistic and empirical models used to simulate shoe track drillout optimization. The current common approach is the use of "best practices," which have been developed by companies throughout years of experience. However, even when the best practices are used, shoe track drillout is often time-consuming and damaging to the operation of the drilling tools.
This paper presents analyses of field shoe track drillouts data, obtained from several wells, to assess the primary drilling controlling parameters with respect to drillout times.
The study reveals primary factors that affect shoe track drillout time. It also provides an understanding of how operational parameters should be manipulated to achieve the desired ROP. Finally, the study results were compared to existing best practices. This comparison was used to create a combined list of recommendations that can be consulted before drilling through a shoe track. Although the elimination of damage to the BHA is an important issue in this topic, it is beyond the scope of this paper and may be the focus of future research.
Hydraulic fracturing is a well-established process to enhance productivity of oil and gas wells. Fluids are used in fracture initiation and the subsequent proppant and/or sand transport. Several chemistries exist for these fluids. This paper summarizes the published literature over the last decade (90+ technical articles) and captures the advances in the design of water-based fracturing fluids. Despite their old introduction, guar-based polymers are still being used in fracturing operations for wells at temperatures less than 300oF (148.9oC). In order to minimize the damage associated with this class of polymers, the industry attempted several approaches. These include the use of lower polymer concentration in formulating these fluids. Another approach was to alter the crosslinker chemistry so that one can generate higher viscosity values with lower polymer loadings. Moreover, the industry shifted towards the use of cleaner guar-based polymers. The reason is the fact that commercial guar contains a minimum of 5 wt.% residues that cause damage to proppant packs. With fracturing deeper wells in hotter reservoirs, the need arose for a new class of thermally stable polymers. Thus, the industry shifted towards polyacrylamide-based polymers. These synthetic polymers offer sufficient viscosity at temperatures up to 232oC (450oF). Examples included 2-acrylamido-2-methylpropanesulfonic acid (AMPS) and copolymers of partially hydrolyzed polyacrylamide (PHPA)-AMPS-vinyl phosphonate (PAV). To address the challenge of high pressure pumping requirements on the surface, high density brines have been used to increase the hydrostatic pressure by 30%. On the breakers chemistry, new breakers were introduced. These breakers decrosslink the gel by reacting with the crosslinker. In order to minimize the environmental impact of using massive amounts of fresh water and to minimize costs associated with treating produced water, the use of produced water in hydraulic fracturing treatments has been reported. In addition, the paper captures the advancements in the use of slickwater where use is made of drag reducing agents (PAM-based polymers) to minimize friction. The paper highlights the first use of breakers that were introduced to improve the cleanup of these drag reducers. For foamed fluids, new viscoelastic surfactants (VES) that are compatible with CO2 are discussed. The paper also sheds light on the use of emerging technologies such as nanotechnology in the design of new efficient hydraulic fracturing fluids. For example, nanolatex silica was used to reduce the concentration of boron used in conventional crosslinkers. Another advancement in nanotechnology was the use of 20 nm silica particles suspended in guar gels. The paper provides a thorough review on all of these advancements.
Directional-drilling processes that involve downhole motors, diamond bits, and bent subs have substantially changed the dynamics and economics of drilling to smaller, and more specific, geologic targets. This process produces some drilling-induced artifacts that include grooves and bit chatter in the wellbore wall. These created environments radically affect the measurements of density/neutron logs. In some cases, the alteration is so great that it affects resistivity logs, which makes the needed log properties impossible to determine with any accuracy.
The porosity measured by the density log appears to cycle high and low as the density pad loses and regains contact with the formation. The neutron porosity is also affected in many cases, exhibiting an identical cyclical character. The porosity measured by either traditional log cannot deliver a correct porosity, which leads to a cross-plot porosity estimate that is not accurate or useful. Another method must be used that does not depend on a smooth wellbore wall.
Dipmeter analysis is also affected because drilling-induced artifacts can be misinterpreted as geologic events. In many cases, the drilling process creates grooves that spiral down the wellbore. These grooves provide very distinct electrical contrasts, and the analyst may interpret them as actual geologic features. The use of an oil-based mud system provides an additional complicating factor that contributes to challenging dipmeter interpretations. Oil-based dipmeter interpretation was not consistent with expected results.
The solution to these difficult interpretation challenges requires the use of a different set of logs that provide answers independent of borehole quality. In this paper, we show how centralized, mandrel-deployed nuclear magnetic resonance (NMR) logs, unaffected by borehole irregularities, were used to define effective porosity. We also show how oil-based imagers were used to differentiate between drilling-induced grooves and beds or formation boundaries.
Peles, J. (Marathon Oil Company) | Wardlow, R.W. (Marathon Oil Company) | Cox, G. (Halliburton Energy Services, Inc.) | Haley, W. (Halliburton Energy Services, Inc.) | Dusterhoft, R. (Halliburton Energy Services, Inc.) | Walters, H.G. (Halliburton Energy Services, Inc.) | Weaver, J. (Halliburton Energy Services, Inc.)
Effective fracture length is the portion of the propped fracture that cleans up after hydraulic fracturing procedure and contributes to well productivity. Studies indicate that this effective length is often less than 10% of the total propped fracture length. A large portion of our fracture stimulation dollars are wasted!
This paper presents a comparative well study performed in the Cement field in south central Oklahoma. Stimulation of the Springer Sands using hydraulic fracturing with conventional low polymer fluids was compared with the use of low molecular weight polymer fracturing fluid. The depth of the three Springer Sands (Cunningham, Britt, and Boatwright) ranges from 12,500 feet to 15,500 feet and have an average permeability range of 0.1 to 5.0 md.
This evaluation includes several components. Well production history matching and pressure analyses are used to determine effective fracture length. Results of these analyses are compared with calculated values based on laboratory generated cleanup data for the two fluid systems. Flowback rate, pressure, accumulated volume, viscosity, and polymer content were collected following the fracture stimulation treatments.
The fluid systems compared in this study are a conventional low polymer system with gel breakers and a new, low molecular weight polymer system that requires no breakers. Both fluids use borate cross-linking chemistry. The low molecular weight fluid system creates transient, high molecular weight polymer chains at higher pH conditions. After exposure to the formation minerals, the pH drops and it reverts to a clean, nearly Newtonian, low viscosity fluid that causes little conductivity damage.
The results of this study show that the use of low molecular weight fracturing fluid provides significant improvements in the effective fracture length over conventional low polymer fracturing fluids. Simple engineering tools have also been developed to evaluate both fluid and proppant selection and job design to achieve improved well performance. It also demonstrated that improved recovery of the fracturing fluid can be achieved at excellent rates without the use of conventional gel breakers.
Simple fracturing fluids, such as linear guar gels, are severely limited in the concentration of proppant that can be successfully transported into the fracture owing to the large density difference. These fluids generally provide transport by viscous drag and depend on fluid velocity to achieve sufficient proppant transport to placement. Fluid rate drops throughout the length of the fracture owing to fluid loss to the formation. This results in the propped length always being less than the frac length.
Viscoelastic fluids have been developed to improve the efficiency of delivering and distributing proppant in fractures. These fluids exhibit two traits, a viscous component that increases viscous drag on proppant and an elastic component that tends to provide proppant suspension. Viscoelastic fluids also create a larger fracture width than simple fluids. Fluids of this type generally increase the proppant concentrations that can be placed by about one order of magnitude over the simple fluids.
Most of the viscoelastic fracturing fluid systems used in hydraulic fracture stimulation employ guar gum or derivatives of guar gum as the basic viscosifing ingredient. Guar is a polymer composed of a linear chain of mannose sugar units with about half of the mannose units having a single galactose sugar unit attached to it. Molecular weight of guar is typically reported to be 3-5 million Daltons with about a 2:1 ratio of mannose to galactose.
The spatial extents of this survey covers much of the Medicine Hat Block from 110 o W low amplitude, high frequency, curvilinear anomalies some of which can be explained by topographic and to 113 W and from 49 N to 50 N and is referred to as the Cypress Hills survey. This survey is displayed in terrain effects, and iv) high amplitude, high frequency, point-like well head casing anomalies. Figure 1 as a false sunshaded gray scale image with Well head casing anomalies present a great challenge illumination from the north east. The survey to remove without removing real geologic signal. An parameters i.e. flight height, line separation; provide attempt at Naudy filtering gives an improvement over an adequate compromise between surveying a wide conventional Fourier processing. Overlaying known area, and obtaining detail.
Interpretation 4: Waulsortian Mound Case Histories Thurs a.m., Nov 14 INT 4.1 ALTREX TM an airborne application for defining hydrocarbon alteration plumes - Denver Julesburg Basin, Colorado, U.S.A. J.D. Rowe*, R.S. Smith, Geoterrex, Canada and R.K. Warren, Warren Geophysical Services, Houston Examples from the Pollen Field are shown and there is an excellent correlation between an enhanced conductivity anomaly and the oil field. The application indicates that alteration plumes may be detected and defined on reconnaissance surveys to detect anomalous areas. The alteration plume has been shown to have anomalous magnetic susceptibilities, in some cases, as documented by Reynolds et al., (1991). The effect of man-made culture (wells, pipes) can also be great, e.g., in the Cement oil field (Reynolds et al., 199 1). Electrical and induced polarization (IP) measurements have also been discussed (Stemberg, 1991), with the strongest anomalies occurring where the near-surface rocks are porous and iron rich.
Squeeze cementing technology is available that allows first attempt success in almost any situation. Gone are the days when three, four, and five attempts were necessary. Even a second attempt is rare when this technology is properly applied.
This paper illustrates three areas of squeeze cementing that are generally misunderstood and misapplied:
1. Injection rates are conducted at excessively high rates and pressures and either create or perpetuate damage. Valuable information that could be used to make the right decisions during the squeeze job is lost forever.
2. Proper slurry design is often neglected. Slurries are almost always tested incorrectly if they are tested at all.
3. The slurry is placed downhole at too high a rate because of the fear of cementing up a workstring. This causes excessive formation damage and places the bulk of the slurry so far from the wellbore that it is of no value to a successful remedial job.
This paper is the result of field studies in which the injection rate, slurry design, and placement procedures were developed and monitored. Field examples are presented. presented
Many slurry designs and placement techniques have been offered for squeezing shallow and low-pressure formations. Everyone involved in remedial work has his own definition of "the right way to squeeze" based on personal perceptions of what has succeeded or failed in personal perceptions of what has succeeded or failed in the past.
Squeeze cementing is defined as the placement of a cement slurry under pressure against a permeable formation causing the slurry to dehydrate and create a cementitious seal across the formation face.
This paper embraces the method known as "Controlled-Water-Loss" (CWL) squeezing. This differs from more traditional methods that use little or no fluid loss control. The two methods contrast most in the rate at which their respective slurries lose filtrate to permeability. Only by controlling the filtration rate can relatively small quantities of cement slurry be directed to small squeeze targets in the well.
The basic principle of CWL squeezing is to understand the zone to be squeezed. After studying and correlating well data and physically measuring the fluid injection profile, a cement slurry and squeeze procedure can be profile, a cement slurry and squeeze procedure can be designed. A technically designed and well-executed remedial cement squeeze will almost certainly be successful.
Since mid-1981, 36 wells have been cemented in the Williston Basin with a cementing system diametrically opposed to conventional cementing designs used for bonding across massive salt members. Since implementation, along with the use of relaxed invert emulsion oil mud, not one casing problem has arisen in the wells where these systems were used.
The Rocky Mountain region provides a myriad of cementing problems. One of these is cementing massive salt members. This is of particular interest to Gulf in their particular interest to Gulf in their operations in the Williston Basin of North Dakota and Montana where numerous and sometimes severe casing problems have been encountered by Gulf and other operators. The salt intervals of interest in the Williston Basin are the Jurassic Dunham salt, the Triassic Pine salt, the Permian Opeche Evaporite, the Pine salt, the Permian Opeche Evaporite, the interbedded salts of the Mississippian Charles Formation, and the Middle Devonian Prairie Evaporite. Also of interest to the Drilling and Production Engineer is the Cretaceous Dakota Formation which is known for its corrosive waters. Doglegged and/or collapsed casing severe corrosion can arise in wells where any or all of these formations are not isolated from the casing by cement. The solution is to insure a contiguous, uniform cement sheath from the top of the Cretaceous Dakota to below the Ordivician Red River. This solution entailed three areas of engineering endeavor: (1) casing design, (2) drilling fluids, and (3) cement. Only the last of these will be detailed in this paper.
DISCUSSION WILLISTON BASIN:
The cementing procedures outlined in this paper are followed by Gulf Oil in all paper are followed by Gulf Oil in all Williston Basin drilling. The Little Knife Field of North Dakota is used specifically because this field is where the cementing procedures outlined below were perfected.
The little Knife Field is located within the counties of Dunn, McKenzie and Billings in North Dakota. To date, 164 wells have been drilled by Gulf. All but two wells in the field produce from the Mississippian Mission Canyon Formation at +9,750 feet (2,972 meters). Two wells are producing from the Devonian Duperow Formation. Of the 164 wells drilled since November, 1976, 13 wells are temporarily abandoned due to low production, 17 wells are plugged and abandoned due to casing failures, plugged and abandoned due to casing failures, 44 wells have casing problems (doglegs, corrosion or tight spots) but are still producible, and 33 wells are still flowing and have not been entered since completion. This means that 37% of the wells drilled in the field have some casing damage. This number may be as high as 57% when all the flowing wells are equipped to pump. Of the remaining 57 pumping wells with no problems, 17 (30%) have been pumping wells with no problems, 17 (30%) have been drilled with a relaxed invert emulsion mud and cemented with a low salt cement.
Three problem areas evolved during the planning, drilling and completion of wells in planning, drilling and completion of wells in the Williston Basin in general and the Little Knife Field in particular. The first problem recognized and addressed was insufficient casing collapse design through salt sections. All casing strings run in the Little Knife Field have been designed with 1 psi/foot (22.6 KPa/m) collapse minimums through all salts encountered and in fact a 1.5 psi/ft collapse (33.9 KPa/m) factor is common across the upper salt members in the Little Knife Field.