Papers by richard hutchins
Dos Cuadras Offshore Polymer Flood
Proceedings of SPE California Regional Meeting, Apr 1, 1990
... P. M., Peterson, RR, Hutchins, R. D. and Dovan, HT, "Implementing an Offshore Polymer Fl... more ... P. M., Peterson, RR, Hutchins, R. D. and Dovan, HT, "Implementing an Offshore Polymer Flood," presented at the American Petroleum Institute ... Tests of Non-Newtonian Fluids," paper SPE 7177 presented at the 1978 Rocky l~ountain Re-gional Meeting, Cody, Wyoming, May 17 ...
A Circulating Foam Loop for Evaluating Foam at Conditions of Use
All Days, Feb 5, 2003
Foam stability is an important parameter for foamed fracturing. Bench-top testing is useful for s... more Foam stability is an important parameter for foamed fracturing. Bench-top testing is useful for screening but does not address the necessary conditions of temperature, pressure, pH (particularly with carbon dioxide [CO2] systems) and dynamic flow conditions which can have unexpected influence on the foam's performance. A laboratory apparatus has been constructed for measuring the rheology of circulating foam fluids to 400°F and 2000 psi. The apparatus is equipped with a circulation pump, view cells, foam generator, mass flowmeter and piping for loading a foam of the desired quality using either nitrogen or CO2. The foam rheometer is intended for evaluation of foam stability with time and comparison of various foam formulations for application in foam fracturing. The foam loop was designed to mimic shear rates found in a fracture or reservoir, which are typically 200 s-1 or less. The rheology is measured by monitoring the pressure drop across a 20-ft length of ¼-in. tubing maintained at temperature in an oven. Flow rate is continually adjusted to ensure a constant shear rate in the tubing by the software using continuous mass flowmeter input. Results relating to CO2 and nitrogen foams are discussed with emphasis on foam persistence, bubble size and population, and the rheological behavior with time. Temperature, pressure, and additives affect both foam texture and foam stability. The adoption of a standard technique patterned after this work for evaluating foam rheology could impact the use and development of foam fluids in the future.
Development of a New Aluminum/Polymer Gel System for Permeability Adjustment
SPE reservoir engineering, May 1, 1987
Summary A new method for gelling Polyacrylamide with aluminum has been developed to reduce the ef... more Summary A new method for gelling Polyacrylamide with aluminum has been developed to reduce the effect of reservoir heterogeneity, resulting in improved waterflood efficiency and higher oil recovery. The method uses a soluble aluminum compound in a high-pH, nonreactive form that is mixed directly with the polymer at optimum concentrations. Polymer gelling occurs in the reservoir when reactive aluminum is generated by consumption of hydroxyl ions. Variations in gel strength and gel time are obtained by adjusting polymer and aluminate concentrations in the slug to the desired levels. This process has several advantages over the current aluminum citrate technology as well as the chromium redox bulk gel system. Although the process works best in freshwater systems, it can be modified to accommodate waters with higher brine content. Laboratory development of the process and a successful profile modification field trial are described.
SPE production & facilities, Nov 1, 1994
A new polymer treatment process has been developed for selectively reducing water permeability in... more A new polymer treatment process has been developed for selectively reducing water permeability in gas wells. Three field treatments are discussed. The most notable treatment was performed on an offshore gas well that previously was loaded up with water. The treatment returned gas production to the well, averaging 1.9 MMcflD gas for almost 3 years. The water production was reduced from a high of almost 600 to < 50 BID. The treatment was performed in 1 day using common oil-and gas-field acidizing equipment. The treatment design was based on information from earlier field treatments, laboratory corefloods, and gel screening data.
Delaying Gelation of Aqueous Polymers at Elevated Temperatures Using Novel Organic Crosslinkers
All Days, Feb 18, 1997
This paper presents novel organic crosslinkers that extend the temperature limitations of current... more This paper presents novel organic crosslinkers that extend the temperature limitations of currently available polymer gel systems. These organic crosslinkers have application in steam injection, geothermal and high temperature oil and gas wells. One crosslinker exhibits a gelation time of several days at 350 F. Long-term stability has been verified for at least one year at 300 F. Some novel organic crosslinkers for low and medium temperature applications are also presented. Introduction Polymer gels have been applied in oil and gas wells for many years to control the flow of fluids within the reservoir. They are inexpensive, simple to apply, versatile in their application and readily available. One major limitation of some gel systems currently in use is that the gelation reactions cannot be delayed for more than several minutes at elevated temperatures. When retardants are used to alleviate this problem, the gel typically weakens and loses some of its gel strength or becomes completely unstable. High Temperature Uses for Gels Several of the organic crosslinkers presented in this paper have application in steam injection wells, geothermal wells and in oil and gas wells where high reservoir temperatures have historically limited the use of polymer gels. Steam Injectors. Steam injection is beneficial to the production of oil in many reservoirs and in particular, to heavy oil reservoirs, by reducing oil viscosities and removing tarry and paraffin deposits. However, due to heterogeneity and to the fact that steam rises to the top of injected zones because of its low density, steam channels can develop leaving potentially productive intervals unswept. Polymer gels and foaming agents have been used to reduce flow through these channels. The temperature in these steam channels can be as high as 500 F which increases the difficulty in forming an in-depth stable foam or gel. Geothermal Wells. Steam and hot water production from geothermal wells are economical sources of energy for the generation of electricity. This production is often accompanied by high concentrations of salts and undesirable gases. Condensate is generally re-injected into the geothermal reservoir and can sometimes detrimentally affect nearby producing well temperatures. Temperatures in these wells could be as high as 600 F. At this time, we do not have a time-delayed gel for these extreme temperatures; however, successful treatments should be possible below 400 F. High Temperature Oil and Gas Wells. Low temperature reservoirs have been successfully treated with current polymer gel technology. However, there is a need to extend these gel treatments to higher temperature formations because of the increasing depths of commercially productive reservoirs. Temperatures of some oil and gas bearing reservoirs can exceed 400 F. Most reservoirs have problems with channeling during primary and enhanced production, but in higher temperature reservoirs, the problem is more difficult to solve by the use of polymer gel treatments. Polymer instability, rapid gelation and improper placement can result in treatment failures.
Field Applications of High Temperature Organic Gels for Water Control
All Days, Apr 21, 1996
As the need to reduce operating expenses has intensified, water control technology has also expan... more As the need to reduce operating expenses has intensified, water control technology has also expanded. One active and continually developing area is the use of polymer gels to control water in both oil and gas fields. Polymer gels typically show a disproportionate permeability reduction which reduces water permeability more than the hydrocarbon phase permeability. A need exists for gels which can be employed in higher temperature reservoirs and which are easily applied in seawater for offshore installations. The organic gel system described in this paper provides a solution to these needs. Because the organic gel system does not employ metal crosslinkers, longer gel delays can be obtained at elevated temperatures and cooling of the reservoir prior to gel injection is not required. The gel system employs low cost, conventional polyacrylamides and is compatible with hydrogen sulfide containing fluids. The gel system can be prepared in seawater and is resistant to oxygen degradation The high temperature organic gel has been developed in the laboratory and tested in numerous field applications. A discussion of four field treatments performed with the organic gel shows the versatility of gels in treating many common problems in the water shutoff area. In two applications, gels have been used in place of cement for perforation abandonment. Polymer treatments were performed successfully in both fractured carbonate and matrix sandstone gas wells to reduce water production and enhance gas recovery. Gel stability has been demonstrated in the field at temperatures as high as 250 F. The gels have reduced water and increased hydrocarbon production. Introduction The use of polymer gels has broadened from the initial conception of shutting off unwanted water in producing wells; however, that practice continues today as the primary usage for polymer gels. Early applications involved the use of viscous polyacrylamide slugs which gradually evolved to the more sophisticated gel systems available today. As applied in the North Burbank Unit, Moffitt has stated that uncrosslinked polymer treatments had good results, but polymer flowback was a problem. Many additional uses have been proposed for crosslinked polymer gels; however, the five major application areas are casing hole repair. cement bond failure repair, zonal abandonment, profile modification and water control in thief zones and coning situations. In nearly every case. organic polymer gels compete with cement squeezes, plastic plugs and inorganic gel systems in the above mentioned applications. The advantages polymer gels have over competitive techniques include lower cost, ease of application, control over gelation time, compatibility with formation fluids and the ability to penetrate substantial distances into the formation. Each candidate well must be evaluated to select the optimum treatment program, considering the lifetime cost rather than the near term application cost. Failures of the technology in the past should be considered in evaluating gel treatments; however, polymer gels are now being applied more judiciously with tighter screening criteria, better design and execution and improved gel chemistry. Several years ago, we started a program to develop gel systems suitable for use in higher temperature reservoirs which primarily required seawater for mixing. The first part of this study was the evaluation of currently available gel systems and their limitations. From this work, a list of needs was assembled to guide the development of a suitable gel system. This effort resulted in the organic gel system discussed in this paper. Review of Currently Applied Technology There are many systems which have been developed for blocking water in porous media including polymer gels, precipitates, resins and cements. P. 419
Dos Cuadras Offshore Polymer Flood
All Days, Apr 4, 1990
An offshore polymer flood in the Dos Cuadras field near Santa Barbara, California was implemented... more An offshore polymer flood in the Dos Cuadras field near Santa Barbara, California was implemented early in 1986. The polymer selection process included laboratory screening and a month long field injectivity test with three prospective polymer suppliers. Polymer injectivity, required polymer concentrations to meet design viscosities, the need for additional polymer inversion chemicals and core plugging behavior of the polymer solution were critical parameters in this evaluation. Full-scale equipment design was aided by observing the performance of skids supplied by each vendor for polymer inversion and injection. Following the selection of a polymer product, shear tests were conducted to improve polymer solution injectivity through Berea core plugs. Although these tests were sufficient to ensure injection into the EP zone, additional shearing of the polymer solution was required to improve injectivity into the FP zone. A filtration test, which was found to be more sensitive than the core plug test to the plugging behavior of polymer solutions, was used to compare properties of injected solutions for the FP zone, Hall plots have been found to be useful for understanding the response of the injection wells to the various injectants.
SPE production & facilities, May 1, 1996
A new polymer gel system developed for high-temperature applications was successfully employed on... more A new polymer gel system developed for high-temperature applications was successfully employed on Well H-43 of the Heather Field to isolate a high-rate water production zone. The high-temperature, organic polymer gel system has demonstrated long-term stability when mixed with seawater at temperatures as high as 350_F. Gel times can be delayed, allowing a large volume of polymer gelant to be placed. For Well H-43, 1,095 bbl of gelant were pumped through 1½-in. coiled tubing into a 15-ft layer of the Brent Group. The treatment increased oil production by 300 B/D and decreased water production by 2,290 B/D. A production log run 8 months later confirmed effective isolation, allowing the lower Brent to produce.
Recent studies have offered evidence of unique shear viscosity loss of borate-crosslinked fractur... more Recent studies have offered evidence of unique shear viscosity loss of borate-crosslinked fracturing fluids when exposed to hydrostatic pressures, such as those encountered during deepwater hydraulic fracturing. This phenomenon can have important implications for proppant transport and for the resulting fracture geometry that needs to be accounted for in fracture design. Another important aspect for fracture design is the fluid loss. Because crosslinked fluids have superior fluid-loss characteristics compared with linear polymers, the question arises as to whether fluid loss of borate-crosslinked formulations is also affected by pressure. Fluid loss is a fundamental property in hydraulic-fracturing treatments and may dictate the attainable fracture geometry and the retained conductivity. Prior knowledge of fluid loss is also important for designing special additives to overcome the effect of excessive fluid loss. This experimental study was designed to determine the pressure effect on linear guar and both borate-and zirconium-crosslinked polymers. The concept of melt point used for the viscosity dependence was incorporated to select fluids. A unique high-pressure/high-temperature fluid-loss apparatus was developed for the experimental testing. Test parameters varied from 160 to 260 F, 1,000 to 9,000 psi, and 0.1-to 10-md sandstone cores. Spurt and fluid-loss coefficients were determined and compared to determine the pressure effect. The results indicate that the fluid-loss behavior of fluids comprising borate-crosslinked guar is susceptible to moderate pressure effects. In particular, spurt losses increased with pressure, whereas fluid-loss coefficients were independent of pressure. The increase in spurt loss varied from 316% for Bandera core (0.1 to 0.4 md) to 1,533% for Parker core (3 to 10 md) when pressure increased from 1,100 to 9,000 psi, exhibiting a pronounced dependency on permeability. Conversely, the fluid-loss behavior for linear guar or derivatized guar (carboxymethyl hydroxypropyl guar) crosslinked with zirconium was not influenced by pressure. The implications of these findings for hydraulic-fracturing applications are also discussed. Experimental Several techniques were used to characterize fracturing fluids and the effect of pressure on fluid loss. Fracturing-fluid viscosity was
All Days, Oct 8, 2012
Enzyme breakers have been previously used for hydrolyzing guar gels at temperatures below 150 F. ... more Enzyme breakers have been previously used for hydrolyzing guar gels at temperatures below 150 F. There is an industry-wide demand for enzyme breakers that can function under highertemperature (200-250 F) and extreme pH (!10.5) conditions. To meet this demand, efforts have been made to develop an exceptionally thermostable cellulase enzyme, referred to hereafter as mannanase, that was originally discovered in a hydrothermal vent sample. This mannanase exhibits well-differentiated performance under extreme downhole conditions encountered in gas shales and deeper oil/gas wells. This superior mannanase can effectively break linear and borate crosslinked guar under broad ranges of temperature (80 F up to at least 225 F as seen by rheology, and up to 275 F using residual activity analysis) and pH (3.0 up to 10.5). The results of rheological tests show that only a small dose is required (100 ppm or less) to achieve the complete break. The enzymatic reaction can be triggered by the changes of temperature and pH during fracturing operations. This mannanase also exhibits a dose response that allows the operator to generate a desirable viscosity/ time profile by adjusting enzyme dosage. Even in the presence of fluid additives, such as buffers, salts, stabilizers, and crosslinkers, this mannanase is active for effective viscosity reduction. This mannanase breaker belongs to the glucanase family. It reduces gel viscosity by specifically targeting b-1,4 glycosidic bonds between the mannose units in guar. The carbohydrateprofiling tests demonstrate that this enzyme effectively and efficiently breaks the long-guar polymers into small, soluble fragments that will eliminate gel rehealing. The conductivity tests demonstrate extensive cleaving of guar and removal of polymer residues that cause formation damage and reduce fracture conductivity.
Aqueous Tracers for Oilfield Applications
All Days, Feb 20, 1991
ABSTRACT As an oil field matures, the need for reservoir information increases. Improved geologic... more ABSTRACT As an oil field matures, the need for reservoir information increases. Improved geological descriptions are frequently necessary for the implementation of numerical modelling or improved oil recovery techniques. Frequently this description can be enhanced by tracer studies. Detecting the location of faults between wells is one specific use for tracing fluid flow. Tracer studies have also been used to complement the information provided by other reservoir characterization methods such as pulse and interference testing. The primary importance of tracer testing is that it provides direct proof that fluid flow has progressed from point A to point B, showing that communication paths exist. In addition, measured tracer breakthrough times are quite useful for inferring the flow characteristics of the reservoir. If the tracer program is poorly designed, the apparent absence of tracer detection at point B may lead to incorrect decisions affecting the management of the reservoir. We will discuss the proper selection and usage of chemicals for tracer testing. Limitations and precautions for individual chemicals will be demonstrated with test data from several field tests. The objective of a tracer test design must be known before a proper test can be implemented. Environmental aspects and analysis of certain tracer materials will also be addressed.
New Results Improve Fracture-Cleanup Characterization and Damage Mitigation
SPE production & operations, Jul 29, 2009
Summary It is well documented that hydraulic-fracture treatments, although successful, often unde... more Summary It is well documented that hydraulic-fracture treatments, although successful, often underperform. Frac-and-pack completions exhibit positive skin values, and traditional hydraulic-fracture completions show discrepancies between the placed propped length and the effective production fracture length. Ineffective fracture cleanup is often cited as a likely cause. This paper presents some of the results of an investigation of fracture-cleanup mechanisms. This investigation was undertaken under a joint-industry project (JIP) active since the year 2002. The data discussed build on the initial results published in early 2006, which indicated that the polymer concentrates only in the filter cake, and that flow along the fracture encounters significant yield stress when the filter-cake cumulative thickness dominates the width of the fracture. The new results presented here demonstrate successful strategies that mitigate the effects of excessive filter-cake thickness. Experimental data demonstrate that flow along the fracture would encounter lower yield stress when the breaker is delivered directly to the filter cake as opposed to random distribution. The data also indicate that a smaller breaker amount delivered directly into the filter cake is more effective at reducing the yield-stress effects than a larger breaker amount delivered randomly in the slurry. Alternative breaker materials are explored, and additional data are also presented to estimate the yield-stress effect for fluid flow across the filter cake from the reservoir into the fracture.
New Findings in Fracture Cleanup Change Common Industry Perceptions
All Days, Feb 15, 2006
This paper summarizes part of the results of an investigation of fracture clean-up mechanisms und... more This paper summarizes part of the results of an investigation of fracture clean-up mechanisms undertaken under a Joint Industry Project active since the year 2002. It is well documented in the literature that hydraulic fractures, although successful, often underperform: Frac and Pack completions exhibit positive skin values, and traditional hydraulic fracture completions show discrepancies between the placed propped length and the effective production fracture length. Ineffective fracture clean-up is often cited as a likely culprit. The main results presented in this paper were obtained using a modified conductivity cell to allow polymer concentration via leakoff, and measurements of flow initiation gradients. The paper will discuss the experimental set-up and some of the artifacts that had to be removed prior to ensuring more reliable data. The results highlight the crucial role played by the filter cake and present new data that would significantly change the common industry practice of relying simply on an average polymer concentration factor.1-3 It is shown that contrary to the current method that calculates an average polymer concentration,the polymer,in practice, concentrates only in the filter cake. It is also shown that the filter cake thickness compared to the fracture thickness plays a critical role in creating significant yield stress effects,which could be either avoided through adequate design or used to estimate the resulting productivity loss.
SPE production & operations, Aug 18, 2015
Recent studies have offered evidence of unique shear viscosity loss of borate-crosslinked fractur... more Recent studies have offered evidence of unique shear viscosity loss of borate-crosslinked fracturing fluids when exposed to hydrostatic pressures, such as those encountered during deepwater hydraulic fracturing. This phenomenon can have important implications for proppant transport and for the resulting fracture geometry that needs to be accounted for in fracture design. Another important aspect for fracture design is the fluid loss. Because crosslinked fluids have superior fluid-loss characteristics compared with linear polymers, the question arises as to whether fluid loss of borate-crosslinked formulations is also affected by pressure. Fluid loss is a fundamental property in hydraulic-fracturing treatments and may dictate the attainable fracture geometry and the retained conductivity. Prior knowledge of fluid loss is also important for designing special additives to overcome the effect of excessive fluid loss. This experimental study was designed to determine the pressure effect on linear guar and both borate-and zirconium-crosslinked polymers. The concept of melt point used for the viscosity dependence was incorporated to select fluids. A unique high-pressure/high-temperature fluid-loss apparatus was developed for the experimental testing. Test parameters varied from 160 to 260 F, 1,000 to 9,000 psi, and 0.1-to 10-md sandstone cores. Spurt and fluid-loss coefficients were determined and compared to determine the pressure effect. The results indicate that the fluid-loss behavior of fluids comprising borate-crosslinked guar is susceptible to moderate pressure effects. In particular, spurt losses increased with pressure, whereas fluid-loss coefficients were independent of pressure. The increase in spurt loss varied from 316% for Bandera core (0.1 to 0.4 md) to 1,533% for Parker core (3 to 10 md) when pressure increased from 1,100 to 9,000 psi, exhibiting a pronounced dependency on permeability. Conversely, the fluid-loss behavior for linear guar or derivatized guar (carboxymethyl hydroxypropyl guar) crosslinked with zirconium was not influenced by pressure. The implications of these findings for hydraulic-fracturing applications are also discussed. Experimental Several techniques were used to characterize fracturing fluids and the effect of pressure on fluid loss. Fracturing-fluid viscosity was
High temperature stable gels
Methods of fracturing formations using quaternary amine salts as viscosifiers
Aqueous Solution for Controlling Bacteria in the Water Used for Fracturing
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Papers by richard hutchins