Selected data on water wells, geothermal wells, and oil tests in Imperial Valley, California

1976 ◽  
Author(s):  
William F. Hardt ◽  
James J. French
Keyword(s):  
Imperial Valley ◽  
Water Wells ◽  
Geothermal Wells

scholarly journals The tasks of hydraulics of steam-water wells in the development of steam-hydrothermal fields

2018 ◽  
Vol 56 ◽  
pp. 01009
Author(s):  
Alla Chermoshentseva ◽  
Alexander Shulyupin
Keyword(s):  
Mathematical Models ◽  
Flow Conditions ◽  
Geothermal Fields ◽  
Water Wells ◽  
Geothermal Wells ◽  
Practical Development ◽  
Hydrothermal Fields

Actual problems and prospects of practical development of geothermal fields are noted in the present work. The mathematical models for the calculation of flows in steam-water geothermal wells are described. The author's models cover the whole range of possible flow conditions.

Water well acidization revisited: includes oil and geothermal well perspectives

2020 ◽  
pp. qjegh2020-071
Author(s):  
Andreas N. Charalambous
Keyword(s):  
Hydrochloric Acid ◽  
Lower Cost ◽  
Oil And Gas ◽  
Fractured Rock ◽  
Oil And Gas Industry ◽  
Gas Industry ◽  
Water Wells ◽  
Water Well ◽  
Geothermal Wells ◽  
Scale Deposits

Borehole acidization has two objectives: to remove drilling damage at the well face and to enhance formation permeability. Acid applications have been mainly on carbonates, granitic and metamorphic rocks in geothermal wells and on sandstones in oil and gas wells. In geothermal wells, acidizations have been especially useful in removing accumulated scale deposits. Hydrochloric acid is the most commonly used as it has a high dissolving power, a lower cost and is relatively easy to handle. It reacts easily with carbonates but not with silicates in sandstones for which a mixture of hydrofluoric and hydrochloric acid is used. There are no known water well acidizations with hydrofluoric acid. Acidization of limestone water wells with hydrochloric acid has been generally successful in naturally fractured rock with productivity improvements of two or more times the original yield. Second and third acidizations can enhance yields further and are usually economically justifiable. Water well acidizations may benefit from higher injection rates than is currently practised. Acid fracturing is widely used in the oil and gas industry. In water wells it may prove useful in hard crystalline limestones, but not in soft low strength carbonates, such as UK Chalk.

Chemical Analyses of Brines From Four Imperial Valley, CA, Geothermal Wells

1980 ◽  
Vol 20 (02) ◽  
pp. 105-112 ◽  
Author(s):  
P.B. Needham ◽  
W.D. Riley ◽  
G.R. Conner ◽  
A.P. Murphy
Keyword(s):  
Flow Rate ◽  
Time Interval ◽  
Geothermal Resource ◽  
Production Engineering ◽  
Stabilization Time ◽  
Imperial Valley ◽  
Geothermal Brine ◽  
Primary Responsibility ◽  
Brine Chemistry ◽  
Geothermal Wells

Abstract A brief report is given of studies of brine chemistry on both high- and low-salinity geothermal fields in support of a field corrosion testing program being conducted by the USBM in the Imperial Valley, CA. Specific results are reported for four geothermal wells: Mesa 6–1, Mesa 6–2, Magmamax No. 1, and Woolsey No. 1. These results demonstrate the necessity for careful reporting of the specific well operating conditions and brine sampling techniques under which the brine analyses were obtained. In particular, information related to recent well shut-in particular, information related to recent well shut-in periods, total stabilization time, recent production periods, total stabilization time, recent production engineering, brine flow rate from the well, and identification of nonturbulent-structure brine-flow configurations must be documented carefully with any reported analyses. Introduction For the past several years, the USBM has been involved in the nation's geothermal program, with primary responsibility for developing technology for primary responsibility for developing technology for recovering important metals and minerals from geothermal brines. Because the most accessible U.S. geothermal mineral resources occur in extremely corrosive hydrothermal fluids, the bureau also has conducted research to identify construction materials for process plants designed to recover these resources.The largest identified geothermal resource area in the U.S. containing substantial quantities of potentially recoverable metals and minerals is in the potentially recoverable metals and minerals is in the Imperial Valley. Of six known geothermal resource areas (KGRA's) there, the Salton Sea KGRA contains brines with the highest mineral content - 25 to 32% total dissolved solids (TDS). The brines from the Salton Sea KGRA, however, are among the most singularly corrosive natural fluids to be found, and during any type of brine processing a wide range of scaling phenomena occurs that can create havoc within a geothermal resource recovery plant. Early attempts to recover these geothermal resources were abandoned, partly due to the failure to overcome these corrosion and scaling problems.This paper presents on-site brine chemical analyses for the early stages of production for four geothermal wells and discusses how these analyses can be influenced by operational conditions. In addition to specifying the analytical and sampling procedures used for geothermal brine analyses, a procedures used for geothermal brine analyses, a number of important conditions concerning the geothermal well in question must be specified for meaningful interpretation of the analytical data. Much of the data reported in the literature does not include this type of information, thus limiting its value. These conditions, defined here as the "reportable conditions for geothermal brine chemistry data," are (1) sampling procedure (to include temperature, pressure, date, type of sampling port, and either suspected or known phase of the port, and either suspected or known phase of the preextracted sample - i.e., brine, steam, or mixed preextracted sample - i.e., brine, steam, or mixed phases), (2) total flow rate from the well (in volume phases), (2) total flow rate from the well (in volume per time interval), (3) shut-in time (if well is being per time interval), (3) shut-in time (if well is being restarted after a period of nonflow), (4) total operating time (of actual brine-flowing operations), (5) production engineering (including any recent perforation, recasing, or bottomhole extension), and perforation, recasing, or bottomhole extension), and (6) variations in baseline chemistry (to distinguish between average operating values and unique well conditions or to specify unusual brine flow patterns).These six points are essential for meaningful comparisons of the brine compositions of different wells, the variations in brine chemistry with time for a single well, and the sampling and analytical results for brines from the same well obtained by different organizations. SPEJ P. 105

Performance of Oilwell Cementing Compositions in Geothermal Wells

1979 ◽  
Vol 19 (04) ◽  
pp. 233-241 ◽  
Author(s):  
J.P. Gallus ◽  
L.T. Watters ◽  
D.E. Pyle
Keyword(s):  
Service Life ◽  
Field Experiments ◽  
Testing Procedure ◽  
Laboratory Evaluation ◽  
Imperial Valley ◽  
Geothermal Well ◽  
Geothermal Fluids ◽  
Geothermal Wells ◽  
Geothermal Environments ◽  
Cement Strength

Abstract Just a few years ago, there existed a great uncertainty regarding the durability of oilwell cements in geothermal wells. Limited, and at times apparently unreliable, information suggested that conventional well cements may not be sufficiently resistant to geothermal well fluids and temperatures for the expected 20- or 30-year service life of the average geothermal well. Therefore, we began to investigate the performance of numerous oilwell cementing compositions in actual geothermal environments.Duplicate samples were exposed to actual geothermal well temperatures and fluids in the Baca, NM, and Imperial Valley, CA, geothermal fields for periods of up to 1 year.A novel testing procedure for geothermal cements was developed and successfully applied in these experiments. Laboratory evaluation of the exposed samples measured the durability of various compositions.The work indicated that some oilwell cements apparently can be rendered sufficiently resistant to geothermal well conditions for the service life of a geothermal well. Introduction The research completed and reported here was prompted primarily by uncertainty about the durability of any cement to be applied in geothermal wells with bottomhole temperatures ranging from 400 to 750 deg. F (204 to 399 deg. C) or produced flashing brine. The required well-service life ranged from 20 to 30 years. Several problems existed. First, the literature contained little applicable information about high-temperature hydrothermal cement chemistry. Prediction of the service life of cements in geothermal environments on the basis of known cement chemistry clearly was impossible. Prediction was of vital concern to operators responsible for safe, as well as competent, geothermal wells, particularly when serious cement-strength retrogression and deterioration generally was known to occur at elevated temperatures.Second, results of an early field test [which exposed samples of oilwell cements as 2-in. (5-cm) precured cement cubes to 600 deg. F (316 deg. C) brine in a geothermal well for periods up to 1 year] strongly suggested that even the three best cementing compositions tested might deteriorate to less than minimum acceptable compressive strengths within 3 to 9 years during geothermal well service. Other field experiments with oilwell cements in contact with produced geothermal fluids also yielded information showing extremely rapid (30- to 60-day) cement deterioration in strength and permeability. Thus, an API Class G cement (without silica) completely disintegrated (to granular size) in 30 days when exposed to 460 deg. F (238 deg. C) steam. Significantly we found that this sample contained (on X-ray diffraction analysis) both dicalcium silicate hydrate and large amounts of calcium hydroxide and carbonate. In another sample of this cement, compressive strength degraded by 77% from 5,050 to 1,150 psi (34.8 to 7.93 MPa) and permeability increased from 0.012 to 8.3 md in 60 days of aging in a produced geothermal brine of only 320 deg. F (160 deg. C) temperature. SPEJ P. 233＾

Drilling water wells in disaster areas

Waterlines ◽  
1988 ◽  
Vol 6 (4) ◽  
pp. 10-13
Author(s):  
Alan Hayes
Keyword(s):  
Water Wells
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