Post on 20-Aug-2020
i | SRK Consulting (U.S.), Inc.
Summary of the BHP Copper Florence ISR Field Test and Updated Work
PRELIMINARY DRAFT
(Never completed in 2010. Selected discussion may now be out of date)
Report Prepared for
Curis Resources Ltd.
SWVP-026347
SWVP-0640
ii | SRK Consulting (U.S.), Inc.
Report Prepared by
SRK Consulting (U.S.), Inc.
204400.03
October 22, 2010
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Summary of the BHP Copper Florence ISR Field Test and Updated Work
Curis Resources Ltd. 1020-800 West Pender Street Vancouver, BC Canada V6C 2V6
SRK Consulting (U.S.), Inc.
3275 West Ina Road, Suite 240 Tucson, AZ 85741
e-mail: tucson@srk.com website: www.srk.com
Tel: 1.520 544 3688 Fax: 1.520 544 9853
SRK Project Number 204400.03 October 2010 Author:
Corolla Hoag, R.G.
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Executive Summary Between 1969 and 1975, an extensive, low-grade porphyry copper deposit was delineated by
Continental Oil Company. The deposit, located north of the Gila River and north-northwest of the Town of Florence, was subsequently owned by Magma Copper Company (Magma) and BHP Copper
Inc. (BHP). These companies invested significant efforts in performing additional exploration
drilling, metallurgical test work, aquifer tests, environmental permitting, biological and cultural
resource studies, geochemical modeling, and pre-feasibility level engineering design work (BHP, 1997a-d).
The deposit is buried by a minimum of 370 feet of unconsolidated basin-fill formations. The pre-
feasibility studies reviewed operational alternatives including open pit-heap leach and in-situ copper recovery (ISCR) methods. The physical characteristics of the deposit made the latter method both
possible and the most economic approach. Extensive aquifer testing was performed to support
environmental permitting, but a field test with raffinate injection and copper dissolutions and
recovery was needed to provide additional data for the economic model and life-of-mine plan. BHP initiated an ISCR field test in 1997. The summary sections below provide a brief overview of the
test goals and results; details are provided in Sections 2 through 8. The intent was to compile and
review the available data and reports, summarize the findings, and provide comments on the lessons learned and recommendations for the future production field test (PTF) to be performed by Curis
Resources Ltd. Additional information on the site history and current status is presented in the NI
43-101 Preliminary Economic Assessment for the Florence Project (SRK, 2010b).
Field Test Overview and Goals
From 1997 through 1999, BHP conducted a field test study for an in-situ copper solution project near Florence, Arizona. The field test design used a wellfield of four injection wells and nine recovery
wells with associated monitoring wells to observe the surrounding water levels and chemical
reactions. The wells were installed in a 5-spot pattern with a distance of 50 ft between each injection and recovery well and 71 ft between each injection well. The wellfield location was situated in a
representative portion of the deposit with a typical oxide zone thickness and an average total copper
grade. The well design was developed to protect the local aquifers and was approved by the Arizona Department of Environmental Quality (ADEQ), the U.S. Environmental Protection Agency, and the
Arizona Department of Water Resources. A tank farm, 7-acre lined pond, and pipeline corridor were
built to support the test. Data collected during the test included well construction records, water
quality analyses, and field records, which were entered into a project database. Instrumentation and software was used and developed to record the:
Flows in and out of the wellfield, pond, and tank farm;
Data from pressure transducer in the wells and conductivity probe measurements;
Water levels in the wellfield, pond, and tanks; and
Measurements from the leak collection and recovery system in the pond.
A dilute injectate using raffinate from the BHP San Manuel solvent extraction/electrowinning (SX/EW) Plant mixed with groundwater from a nearby well was injected into the oxide mineralized
deposit via the four injection wells. The injected solution traveled through fractures and porous spaces in the highly fractured bedrock, reacted with the copper-bearing minerals, and dissolved and
transported the copper in solution. The solution was then recovered by a series of recovery wells
(also known as production or pumping wells) surrounding the injection wells and sent to the
evaporation pond; copper cathode was not produced. During the test, the injection rate into the wellfield was approximately 121 gallons per minute (gpm) and the recovery rate was 150 gpm – a 20
percent over-pumping rate. This was done to maintain an inward hydraulic gradient towards the
center recovery well BHP-1. The demonstration that inward hydraulic gradient could be maintained
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through differential pumping rates was required by ADEQ as a condition of the test and future
operations.
The goals of the test were to demonstrate that copper could be economically extracted via the ISCR
method while ensuring compliance with environmental regulatory requirements. The test was
intended to continue until enough data were collected to forecast the ultimate copper recovery, rate of copper recovery, and acid consumption that would occur during the planned 5-year operation of a
representative mine block. It would provide information about the build-up of other constituents in
the raffinate and pregnant solution and provide actual operations experience related to this deposit. Additionally, the test was to provide field experience on the best method to install the wells, prove
that the design would meet the mechanical integrity requirements, and provide cost data to apply to
an estimate of capital and operating costs. With recovery data in hand, BHP would have the
necessary information to estimate mineral reserves for the project and prepare a feasibility level life-of-operations plan and economic model.
Field Test Results
Although the raffinate-injection phase was originally intended to run approximately 9 to 12 months,
it was truncated prematurely after only 101 days owing to changes in corporate BHP objectives. As a result some major goals of the test, such as a determination of expected metal recovery and other
metallurgical results, were not achieved. The field test did, however, successfully demonstrate other
aspects relevant to the operation of a copper ISR facility, and the experience can be applied to the
future PTF.
The test operated during a learning period when the best installation and data recording methods
were still being developed, operators were being trained, and experiments were made with the ratio
of raffinate in the injectate. After an initial learning curve to work through the best installation methods, an effective technique and routine was developed to drill the borehole and install grouted
casing, perform the mechanical integrity tests, log and collect assay samples, develop the formation,
install the necessary compliance monitoring and production infrastructure, and operate the wells, tank farm, evaporation system, and other test facilities in a safe manner. Results of the test are
briefly summarized below.
Well Design and Mechanical Integrity
The basic well design was shown to meet mechanical integrity and production performance
standards required for Class III wells during the time they were in use. The design was at a cost-
effective level during the late 1990s when copper prices were much lower than they are today. The
5-year well performance audit of mechanical integrity has not performed so no conclusions can be drawn yet on the ultimate durability of the pumps, well casing and joints, and the cement bond
between the borehole wall and the polyvinyl chloride (PVC) casing during the post-test period.
Injection and Leaching Effectiveness
Average injection rates in injection wells BHP-6 to BHP-9 ranged from 21 to 35 gpm during the
period of raffinate injection. Pumping rates ranged from 10 to 13 gpm in the outer recovery wells
(BHP-10 to BHP-13) and 14 to 19 gpm in the inner recovery wells (BHP-2 to BHP-5). The central recovery well BHP-1 was pumped at a rate of 39 gpm to maintain an inward gradient. Some well
clogging occurred during the leaching phase, which decreased the pumping rates over time. The
clogging was caused by a gelatinous alumino-silicate precipitate that apparently developed because the area under leach was at intermediate pH levels and was not acid-equilibrated. The problem was
solved with the injection of raffinate around the pumps, which dissolved the precipitates.
The pH of the injectate was generally kept between 1.5 and 1.7; the composition of the injectate became more dilute over time – starting at an 8.5% raffinate to water ratio and ending at 4.1%
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raffinate to water. Low-pH injectate traveled from the injection wells and interacted with the gangue
minerals encountered along the flow path. During the raffinate injection phase the groundwater within the inner recovery wells gradually decreased from background values (pH 7-8) to pH 3.04
measured in BHP-1 and BHP-5 at test termination. Chrysocolla was dissolved and recovered as
copper-bearing pregnant solution in the inner and outer recovery wells to varying degrees of effectiveness. Water quality samplers placed within the two chemical monitor well CH-2 and CH-2
provided information on the breakthrough across the flow path at three discrete elevations.
Breakthrough and development of acid-equilibrated conditions developed within two weeks in the upper two thirds of the injection zone at CH-2 but was delayed in the bottom one-third – perhaps
indicating the presence of less fractured or less conductive rock. Recovery wells BHP-2, BHP-3,
and BHP-4 were still showing intermediate pH values (5.7-6.3) at test end with resulting limited
copper recovery. The outer recovery wells experienced continuous in-flow and dilution of neutral pH groundwater, which prevented effective copper recovery.
Estimate of Acid Consumption
Metallurgical test work (vat leach tests, bottle roll, column tests) performed by Conoco, Magma, and
BHP indicated that acid consumption ranged from a minimum of 7.6 to a maximum of 43.7 lbs acid
per lb copper produced. BHP estimated the average net acid consumption to be 3 lb acid per lb
copper produced based on the results of column tests. The correlation between these laboratory results in terms of acid consumption and copper recovery, however, and what would be seen in the
field conditions with much lower porosity and flow rate relative to column tests was uncertain (and a
major goal of the field test). Raffinate injection did not continue long enough in the field test to achieve free acid breakthrough (pH~<3.5) in most of the inner recovery wells so acid consumption
and copper recovery rates were not confirmed. Based on a review of the historic metallurgical tests,
however, SRK Consulting (SRK) believes the average net acid consumption will likely be higher at
5 lb acid per lb copper produced. This includes 4 lb acid consumption in the wellfield and 1 lb acid consumption in the plant.
Rinsing Effectiveness
Following the cessation of the raffinate injection phase on February 8, 1998, a period of rinsing
began in order to restore the water quality in the oxide bedrock aquifer to meet regulatory
requirements. The Underground Injection Control Permit required the resource block (field test) to
be restored to the primary maximum contaminant level or to pre-mining background concentrations. The ADEQ Aquifer Protection Permit required restoration to meet Arizona Aquifer Water Quality
Standards (AWQS). Rinsing was completed using the residual pond water and water from nearby
water well WW-4; no rinsing amendments were used.
SRK compiled the water quality and flow records for the field test through May 1999. This included
the period of raffinate injection, injection of the residual pond water, and injection of groundwater
through May 12, 1998. It also includes the year-long period through May 11, 1999 where groundwater withdrawal occurred with no injection. Although limited pumping did continue
through the end of December 1999, SRK does not have complete flow records for dates past May
1999. An internal memorandum prepared by BHP (Kline, 2001) provides recovery information on
the period through December 2001.
Modeling performed in 1995 by Brown and Caldwell (B & C, 1996b) predicted what the water
quality of the wellfield and downgradient areas would be after closure. Their model indicated that
rinsing the injection zone to bring the sulfate concentration to below 750 mg/L would ensure that the concentrations of the various associated constituents would meet the maximum regulatory limits.
BHP rinsed the oxide aquifer in the field test area until the water quality within the test area met the
AWQSs. This was achieved for all inorganic trace metals within 12 months. Elevated gross alpha and adjusted gross alpha particle activity were detected in a number of wells through 2004. No
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process-related organic constituents were measured during the rinsing phase. As of 2007, the pH in
the injection wells was increasing but was still below 5.5 indicating that hydrogen release is still occurring; all other wells are at neutral, background pH levels.
Extraction Mass Balance – Sulfate and Copper
Sulfate was introduced through several sources including infiltration groundwater in the oxide
bedrock, and from the combination of sulfuric acid, raffinate, and WW-4 groundwater that was used
in the injectate. Sulfate was deemed to be negligible in the sodium hydroxide solution used to
neutralize the pond water.
Sulfate is a conservative tracer that can be used to monitor the effectiveness of the recovery wells
and environmental impacts related to operations. Some loss in sulfate mass was expected to occur,
but it is difficult to assign the percentage loss to each mechanism. The loss mechanisms include:
Flare-up of injected solutions into the Lower Basin-Fill Unit (LBFU) at the bedrock-LBFU
contact and potential transport away from the recovery wells;
Precipitation of epsomite or other insoluble minerals within the formation;
Precipitation of gypsum from sulfate-saturated solutions in the evaporation pond; and
Minor windborne loss during operation of the mister system in the pond (Kline, 2001).
A mass balance was performed by SRK using primarily the injection/pumping flow records and the water quality analyses of injectate and recovered solutions. Based on the data available to SRK,
approximately 89 percent of the net sulfate injected into the field test area was recovered by May 11, 1999. The sulfate mass balance information compiled by BHP indicates that 94 percent of the
injected sulfate was accounted for by August 1999 and 98% of was accounted for by June 2001
(Kline, 2001).
SRK prepared an estimate of the mass of copper recovered during the leaching and rinsing phases through May 11, 1999. The majority of the copper recovered from the field test was in the inner
recovery wells (BHP-1 and BHP-5). Groundwater dilution kept pH levels at neutral values in the
outer recovery wells BHP-10 through BHP-13, which caused low copper recoveries. The total copper extracted from October 31, 1997 to May 11, 1999 was 41,966 lbs. The net cumulative
copper mass recovered after the subtraction of copper contained in the injectate was approximately
39,743 lbs through May 1999. Approximately 2,223 lbs of copper mass (5.2% of the total extracted)
was injected back into the wellfield and not recovered – probably through precipitation in fractures or re-adsorption in montmorillonite or other clay minerals during the injection of intermediate pH,
copper-bearing pond water during the rinsing phase. The net copper recovery represents a small
fraction (3%) of the 1.34 million lbs copper estimated to be contained in the volume of rock within the inner recovery wells.
Conclusions and Recommendations for the PTF
The first field test was successful at achieving many of the hydrological, engineering, and
environmental goals that were set for the project. Significant effort was spent by the BHP science
and engineering staff to design the wellfield and plant facilities, develop the well construction methods, and perform hydrological and geochemical modeling to understand the results. Pre-test
geology and geophysical test work identified the rock and pre-test conditions. Pre-leaching injection
tests and post-leaching tracer tests added valuable information about the behavior of the wellfield before and after the raffinate injection phase. Chemical analysis of waters derived during and after
the raffinate injection phase revealed complex hydrochemical and mineralogical reactions were
occurring during the interaction of groundwater and injectate, not all of which are fully understood at this time.
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The test was operated in a representative area of E-NE trending granodiorite dikes and quartz
monzonite porphyry host rocks containing average copper grade; copper mineralization consists primarily of chrysocolla and Cu-impregnated clay and iron hydroxide minerals. After sulfide
mineralization, the rock was faulted, weathered, and heavily fractured leading to a condition in
which an oxide zone was created that has a porosity of 6 to 8 percent and aquifer properties (on a global deposit scale) resembling “equivalent porous media.” On a site-specific basis, local
heterogeneities do exist that may dominate the behavior seen in any particular test cell.
Heterogeneities may include the presence of a fault zone (aquitard or high-flow zone), a low-conductive zone within various fault zones, or host rock mineral compositions with greater than
average calcite or exchangeable clays. These local heterogeneities, including potential short-circuits
and preferred pathways, will be difficult to forecast on a site-specific basis and may be encountered
in any single field test cell selected.
The scale of an isolated test cell surrounded by recovery wells that continuously draw in fresh, non-
acidified groundwater makes determination of economic copper recovery difficult and will be of
concern in the future Curis PTF. Total copper recovery and the recovery rate in a single cell will be best understood from reactions seen in an inner set of pumping wells with companion chemical
monitoring wells. The outer recovery wells will likely not achieve the low pH required to dissolve
copper and will primarily function as an intermediate-level pH “fence” protecting the inner recovery wells from dilution by higher pH background formation waters.
Geochemical evidence during the BHP field test points to a significant amount of dilute solutions
being mixed with raffinate even at BHP-1. No combination of known cation exchange, surface
complexation, and dissolution/precipitation was discovered or modeled that could explain the chemistry in the production wells without mixing with dilute groundwater (BHP, 1999). During full
production, the injection zones in contiguous areas will reach acid-equilibration conditions that will
enable dissolution of the copper contained on fractures and within the broken rock. The behavior seen in several sets of inter-connected injection and recovery wells will provide average results that
would diminish the effects of local heterogeneity.
Although the raffinate injection phase was not of sufficient length to assess the economic concepts,
the field test provided invaluable ground-based experience to consider in the operation of the Curis PTF. The PTF ideally would operate long-enough to see breakthrough of acidified injectate and the
complete development of the copper recovery curve within the inner recovery wells. Of prime
importance is the fact that it appears that the aquifer quality can be restored to meet regulatory requirements primarily through flushing with local groundwater. Additional metallurgical test work
is recommended in regards to pre-treatment options to address cation exchange behaviors and
potentially accelerate copper dissolution. A review of post-leach rinsing treatments is also recommended to address elevated gross alpha particle activity.
The PTF should assess more than one construction method as related to drilling and casing costs,
benefits of various casing materials, installation time needed, ease of construction, and effectiveness
in adhering to environmental restrictions. The life-of-operations plan requires a large number of wells to be constructed in the year before operations begin and in each year following for the first
few years. Adjustments in borehole and casing diameters and casing materials will have a
substantial effect on the capital costs.
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Table of Contents
Executive Summary ................................................................................................................... ii
1 Introduction .................................................................................................................. 1
1.1 Available Field Test Data and Acknowledgments .............................................................. 2
1.2 Site Selection for BHP Field Test Area .............................................................................. 3
2 Geology ......................................................................................................................... 4
2.1 Deposit Geology and Mineralogy ....................................................................................... 4
2.2 Geologic Characterization of Field Test Area..................................................................... 5
2.2.1 Summary of Drilling Methods .................................................................................. 5
2.2.2 Downhole Geophysical Methods and Data Interpretation ...................................... 10
2.2.3 Geologic, Structural, and Mineralogy Logging Methods......................................... 11
2.2.4 Sampling and Analysis Methods ........................................................................... 13
2.3 Preparation of Geology Model for Field Test Area ........................................................... 13
2.3.1 Structure Compilation ............................................................................................ 13
2.3.2 Detailed Lithologic Model ...................................................................................... 14
2.3.3 Summary of the Field Test Area Geology .............................................................. 15
2.3.4 Mineral Resources of Field Test Area – 2010 Estimate ......................................... 15
2.4 Conclusions and Lessons Learned .................................................................................. 20
2.5 Recommendations for New Field Test ............................................................................. 20
2.5.1 Proposed Location of PTF and Associated Surface Disturbance........................... 20
2.5.2 Drilling Methods .................................................................................................... 21
2.5.3 Geology of Curis PTF ............................................................................................ 22
2.5.4 Logging, Sampling, and Assaying Protocols.......................................................... 25
3 Design of Test Facilities ............................................................................................ 26
3.1 Well Construction Design ................................................................................................ 27
3.1.1 Injection and Recovery Wells ................................................................................ 27
3.1.2 Chemical Monitoring Wells .................................................................................... 27
3.1.3 Observation Wells ................................................................................................. 28
3.1.4 Cementing Practices ............................................................................................. 28
3.1.5 Mechanical Integrity Tests ..................................................................................... 29
3.1.6 Wellhead Design ................................................................................................... 29
3.2 Test Facilities Design ...................................................................................................... 35
3.2.1 Tank Farm ............................................................................................................ 36
3.2.2 Piping and Surface Layout .................................................................................... 36
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3.2.3 Fluid Management and Filtration ........................................................................... 40
3.2.4 In-ground Environmental Monitoring Methods ....................................................... 41
3.3 Conclusions and Lessons Learned .................................................................................. 43
3.4 Recommendations for New Field Test ............................................................................. 43
4 Hydrologic Site Characterization .............................................................................. 45
4.1 Hydrogeological Characterization of the Deposit ............................................................. 45
4.1.1 Pump Tests ........................................................................................................... 46
4.1.2 Measurement of Anisotropy .................................................................................. 47
4.1.3 Well Capacity ........................................................................................................ 47
4.1.4 Hydrophysical Logging .......................................................................................... 47
4.1.5 Regional Flow and Transport Model ...................................................................... 49
4.2 Hydrogeological Characterization of Field Test ................................................................ 50
4.2.1 Field Measurements and Data Management ......................................................... 50
4.2.2 Pre-Leach Aquifer Pump Tests ............................................................................. 51
4.2.3 Groundwater Injection Tracer Test ........................................................................ 52
4.2.4 Numerical Modeling .............................................................................................. 54
4.2.5 Estimation of Porosity and Dispersivity .................................................................. 54
4.2.6 Evaluation of Hydraulic Control ............................................................................. 55
4.2.7 Sweep Efficiency Estimation ................................................................................. 56
4.2.8 Well Clogging Considerations ............................................................................... 56
4.2.9 Well Bromide Tracer Test Post-Leaching .............................................................. 57
4.2.10 Summary of Injection and Tracer Tests ................................................................. 59
4.2.11 Flow and Transport Modeling ................................................................................ 62
4.2.12 Hydraulic Containment Results ............................................................................. 66
4.3 Conclusions and Lessons Learned .................................................................................. 68
4.4 Recommendations for New Field Test ............................................................................. 68
4.4.1 Data Management................................................................................................. 68
5 Geochemical Characterization .................................................................................. 70
5.1 Summary of Metallurgical Test Work ............................................................................... 70
5.1.1 Summary of Previous Test Work ........................................................................... 70
5.1.2 Bottle Roll Tests .................................................................................................... 71
5.1.3 Large-Scale Column Tests .................................................................................... 73
5.1.4 Summary of Fracture Mineralogy Studies ............................................................. 77
5.2 Geochemical Modeling .................................................................................................... 78
5.2.1 Summary of Pre-test Geochemical Modeling ........................................................ 78
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5.2.2 Summary of Post-Leach Geochemical Modeling ................................................... 78
5.3 Conclusions ..................................................................................................................... 81
5.4 Basis of Design ............................................................................................................... 82
5.5 Recommendations........................................................................................................... 83
6 Operations Activities through Reclamation Phase ................................................. 84
6.1 Field Test Duration .......................................................................................................... 84
6.2 Field Test Operation Procedures ..................................................................................... 84
6.3 Manpower Requirements and Duties ............................................................................... 84
6.4 Evolution of the Water Quality in the Field Test through Rinsing Phase ........................... 85
6.4.1 Sulfate................................................................................................................... 86
6.4.2 pH ......................................................................................................................... 88
6.5 Copper Recovery and Mass Balance............................................................................... 91
6.6 Sulfate Recovery and Mass Balance ............................................................................... 94
6.7 Conclusions and Lessons Learned .................................................................................. 96
6.8 Recommendations for the New Field Test ....................................................................... 96
7 Environmental and Safety Findings ......................................................................... 98
7.1 Environmental Issues during Operation of Field Test ....................................................... 98
7.2 Environmental Issues following the Test - Post-Rinsing Water Quality ............................ 98
7.3 Safety Issues ................................................................................................................... 98
7.4 Conclusions and Lessons Learned .................................................................................. 99
7.5 Recommendations for New Field Test ............................................................................. 99
8 References ................................................................................................................ 105
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List of Tables
Table 1-1 Current Florence Project in-situ mineral resources (SRK, 2010b) ................................ 2
Table 2-1 Summary of drilling method and downhole surveys ..................................................... 8
Table 2-2 Development schedule for 5-spot drillholes, July-November 1996 ............................... 9
Table 2-3 Drillhole assay statistics for the field test area ........................................................... 16
Table 2-4 Mineral resources in BHP field test area .................................................................... 16
Table 3-1 Summary of well construction details......................................................................... 34
Table 3-2 System problems and resolutions .............................................................................. 43
Table 4-1 Correlation of geologic and hydrogeologic units in the basin fill formations................ 46
Table 4-2 Hydraulic parameters of hydrogeological units .......................................................... 46
Table 4-3 Hydraulic conductivity and storativity from the oxide aquifer tests ............................. 51
Table 4-4 Duration of injection tests .......................................................................................... 60
Table 4-5 Average injection and pumping well rates during leaching phase .............................. 66
Table 5-1 Summary of test parameters for bottle roll tests ........................................................ 72
Table 5-2 Statistical summary of bottle roll tests ........................................................................ 73
Table 5-3 Summary of results from scoping phase columns, METCON .................................... 74
Table 5-4 Summary of results from Phase I column tests .......................................................... 75
Table 5-5 Summary of results from Phase II column tests, BHP San Manuel ............................ 76
Table 6-1 Field test shift schedules ........................................................................................... 85
Table 6-2 Mass of copper injected and recovered during leaching and rinsing phases.............. 92
Table 6-3 Mass of sulfate injected and recovered during leaching and rinsing phases .............. 95
Table 6-4 Timeline for leaching and reclamation activities ......................................................... 97
Table 7-1 Post-rinsing water quality results – All wells, 4th Quarter 2000 ................................ 100
Table 7-2 Post-rinsing water quality results – All wells, 2nd Quarter 2001 ............................... 101
Table 7-3 Post-rinsing water quality results – All wells, 4th Quarter 2003 ................................ 102
Table 7-4 Post-rinsing water quality results – All wells, 4th Quarter 2004 ................................ 103
Table 7-5 Post-rinsing water quality data – All wells, 2nd Quarter 2007 .................................. 104
List of Figures
Figure 1-1 Location map – Curis Resources Ltd. Florence Project .............................................. 1
Figure 2-1 Geology plan map at 700 ft elevation above mean sea level ....................................... 6
Figure 2-2 East-west geology cross section 744870N looking north ............................................. 7
Figure 2-3 North-south geology cross section 649500E looking east............................................ 7
Figure 2-4 Selected core photos of BHP-1 through BHP-4 ......................................................... 10
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Figure 2-5 Geology plan map through field test area; 700ft amsl ................................................ 17
Figure 2-6 N-S geology section 649370E through field test area looking east (L) and E-W section 744925N through field test area looking north (R) ..................................................... 18
Figure 2-8 Perspective views of the Tgdp dikes looking due W, -60 degrees (left) and S45°E, -75 degrees (right) ........................................................................................................... 19
Figure 2-9 Plan view of volume of rock within field test designated for resource calculation ....... 19
Figure 2-10 Proposed location of Curis PTF and associated disturbance ..................................... 23
Figure 2-11 Geology plan map of PTF, 900 ft amsl (upper); E-W geology profile 744600N looking north (left) and N-S geology profile 649250E looking east; (Tgdp is blue, Yqm is buff)24
Figure 3-1 Field test layout ......................................................................................................... 26
Figure 3-2 Well construction design – Injection and recovery wells ............................................ 31
Figure 3-3 Well construction design – Chemical monitor wells ................................................... 32
Figure 3-4 Discrete sampler for chemical monitoring wells ......................................................... 33
Figure 3-5 Wellhead infrastructure design .................................................................................. 35
Figure 3-6 Excavated pond, earth pile to northwest, tank farm, and wellfield to west .................. 37
Figure 3-7 Evaporation pond, floating dock, and boat for access to pond and sprayers.............. 38
Figure 3-8 Evaporation pond embankment, liner keyed into berm, and 8-foot anchor fence ....... 38
Figure 3-9 Senniger high-evaporation sprayers floating on 3-in welded HDPE piping. Yellow Jerry cans are for flotation support ............................................................................ 39
Figure 3-10 Ratio of San Manuel raffinate to injectate during field tests ....................................... 40
Figure 3-11 Annular resistivity in Kohms ...................................................................................... 42
Figure 4-1 Aquifer test locations in the deposit area ................................................................... 48
Figure 4-2 Horizontal anisotropic test at the P13 well cluster ...................................................... 48
Figure 4-3 Horizontal anisotropic test at the P19 well cluster ...................................................... 49
Figure 4-4 Percentage of permeable intervals as a function of threshold length ......................... 49
Figure 4-5 Electrical conductivity breakthrough curves during groundwater injection test ........... 52
Figure 4-6 Sulfate breakthrough curves during the groundwater injection test ............................ 53
Figure 4-7 Diagonal NW-SE section (looking southwest) showing screened intervals in undifferentiated bedrock and the faults between BHP-1 and BHP-2 .......................... 53
Figure 4-8 Hydraulic conductivity zones within the oxide bedrock in the 5-spot .......................... 54
Figure 4-9 Simulated vertical concentration profile between injection wells BHP-6 and BHP-8 ... 56
Figure 4-10 Relative Br concentration vs. time curves (BHP, 1999).............................................. 58
Figure 4-11 Diagram representation of Br percentage reaching pumping wells ............................ 59
Figure 4-12 Contoured percentage of sulfate mass recovered during pre-leach groundwater injection test (3/12/1997). BHP-1 is the injection well. .............................................. 61
Figure 4-13 Contoured percentage of sulfate mass recovered during raffinate injection and rinsing phase (10/31/1998 to 5/12/1998). BHP-6 through BHP-9 are injection wells. ........... 61
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Figure 4-14 Contoured percentage of bromide recovered by well during bromide tracer test (5/13/1998 to 7/17/1998) ........................................................................................... 62
Figure 4-15 Field drawdown curves and the calibrated drawdown curves .................................... 64
Figure 4-16 Relative concentrations seen in sulfate field data and calibration results ................... 65
Figure 4-17 Simulated (magenta) and measured (dark blue) bromide concentrations in BHP-6, BHP-7, BHP-8, and BHP-9 ........................................................................................ 65
Figure 4-18 Net positive pumping rate in the wellfield (BHP, 1999) .............................................. 67
Figure 4-19 Potentiometric map for February 2, 1998 (contours in ft amsl)................................... 67
Figure 5-1 Copper recovery curves for column tests .................................................................. 77
Figure 5-2 Copper recovery curves of the long-term forecast model........................................... 80
Figure 5-3 Copper and pH curves from long-term forecast model. Case A production shown as solid lines, Case B shown as dashed. ....................................................................... 81
Figure 6-1 Planar view showing field test layout and location of the wells in mine coordinates (ft)87
Figure 6-2 Planar view showing SO4 (mg/L) concentration near the start of raffinate injection on November 7, 1997 (left) and end on February 1, 1998 (right) .................................... 87
Figure 6-3 Planar view showing SO4 (mg/L) concentration at the end of pond water injection on March 21, 1998 (left) and the end of groundwater injection on May 14, 1998 ............ 88
Figure 6-4 Planar view showing pH (su) on October 31, 1997 (left) and November 3, 1997 (right)89
Figure 6-5 Vertical E-W profile from BHP12 though BHP10 looking north showing pH on November 7, 1997 (left) and at the end of the raffinate injection phase (February 8, 1998) ......................................................................................................................... 90
Figure 6-6 Vertical E-W profile from BHP-12 though BHP-10 looking north showing pH on March 21, 1998 (left) at the end of pond water injection and at the end of the groundwater injection phase (May 14, 1998). ................................................................................. 91
Figure 6-7 Daily and cumulative injection and extraction – Net copper (lbs) recovery vs. time through May 11, 1998 ............................................................................................... 93
Figure 6-8 Daily and cumulative injection and extraction – Net copper (lbs) recovery vs. time through May 12, 1999 ............................................................................................... 94
Figure 6-9 Mass injection and extraction - Net sulfate recovery vs. time through May 12, 1999 . 96
Appendices
Appendix A: Wellfield Extraction Graphs
Appendix B: Water Quality Graphs
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1 Introduction The Florence Project hosts a shallowly buried porphyry copper deposit located in Pinal County,
Arizona near the town of Florence (Figure 1-1). The deposit contains a Measured + Indicated
mineral resource of oxide material in bedrock of 429.5 million tons grading 0.331 percent total copper (%TCu) for a contained 2.84 billion pounds copper (Table 1-1, SRK, 2010). The deposit was
discovered in 1969, and underwent extensive exploration drilling and evaluation for development
during the 1970s by Continental Oil Company (Conoco). During the 1990s, the project was acquired by Magma Copper Company, which was then acquired by BHP Copper Inc. (BHP Copper or BHP)
in 1996. The project was taken to a pre-feasibility-study level by BHP as a proposed in-situ copper
solution recovery (ISCR) operation. Curis Resources (Arizona) Inc. (Curis), a wholly owned subsidiary of Curis Resources Ltd., acquired a 100 percent interest in the project on February 24,
2010, and seeks to reactivate the project toward eventual ISCR copper production.
Curis requested that SRK review the results of the BHP field test performed from October 31, 1997
through February 8, 1998. The field injection and recovery test was prematurely concluded after 101 days, so a full recovery curve for copper extraction was not developed. The raffinate injection
(leaching) phase of the field test was preceded by a pump interference test and groundwater injection
test with M10-GU water. The raffinate injection phase was followed by a bromide tracer test using WW-4 groundwater, and finally a rinsing and reclamation pumping phase. The intent of this report
is to summarize the results, findings, and “lessons learned” with the goal that this information may
be relevant to the operation of a future planned ISCR test.
Figure 1-1 Location map – Curis Resources Ltd. Florence Project
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Table 1-1 Current Florence Project in-situ mineral resources (SRK, 2010b)
All Oxide in Bedrock at 0.05% TCu cutoff
Class Mtons %TCu Grade MLbs Cu
Measured 296.395 0.354 2,100
Indicated 133.091 0.278 741
M+I 429.486 0.331 2,841
Inferred 92.752 0.267 496
Note: All oxide includes the copper oxide zone and iron-oxide leached cap zone including the bedrock exclusion zone. Contained metal
values assume 100% metallurgical recoveries.
1.1 Available Field Test Data and Acknowledgments
SRK has compiled a significant amount of the available technical reports and historic field data related to the BHP field test. The hard copy geology drill logs, downhole geophysical data, well
construction records, and other data were scanned as was the environmental management of the
facility including the daily/week inspections. Curis scanned the 35-mm photos of the drill core
boxes and provided copies of backups from the BHP computer files. BHP field test records were stored in a Microsoft Access database and supplementary Excel spreadsheets; the water quality and
flow data were then consolidated by SRK into a unified database. SRK prepared a 3-dimensional
(3-D) geology and structural model for the field test area using the BHP drillhole data. Animations were prepared to understand the spatial and temporal water quality changes during the leaching and
rinsing phases.
Some field test records such as a schematic drawing of the test facilities and as-built drawings for the tank farm, evaporation pond, and wellfield are not currently available. The manuals for operation of
the facility are available in hard copy format but were not scanned or transcribed for this effort.
Hard copy records for field measurements (water level, chemistry) and analytical laboratory reports
do exist but were not scanned. Data logger records do exist digitally but were not extracted from the BHP backups. The computer programs that controlled the wellfield operations are available but
have not been reviewed for effectiveness or updates that may be needed.
A number of reports by BHP and their consultants were scanned including internal reports and memoranda, two University of Arizona theses, the results of metallurgical tests, and results from
downhole aquifer tests. BHP summarized their field tests and simulations in two documents – the
1997 Final-Prefeasibility Report (BHP, 1997a, b, c, d), and the 1999 Field Test – Goals, Results, and Conclusions (draft dated October 1999). The 1999 report was never finalized but does contain
extensive geochemical and hydrological summaries, some of which were incorporated into the
current report. The major contributors to the two BHP reports were:
Corolla Hoag and Jacqueline Seguin, Geology and Mineral Resources,
Dr. Guoliang Chen, Dr. Shlomo Orr, and Damaris Chong-Diaz, Hydrology and Wellfield
Design;
Dr. Richard Beane and Richard Preece, Geochemistry and Mineralogy; and
John Kline, Environmental and Legal, Plant Design, Processing, and Economic Model.
Contributors to the summary presented herein include:
Corolla Hoag, Geology and Mineral Resources, Operations,
Daniel Russin, Geology Model, Geology Sections,
Michael Sieber, Vladimir Ugorets, and Matt Hartmann, Hydrogeology,
Dr. Terry McNulty, Metallurgy; and
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John Kline, Operations and Recovery Summary.
1.2 Site Selection for BHP Field Test Area
The process to select the location of the BHP field test area included a careful review of a number of physical characteristics including the deposit geology and structure, surface features, and proximity
to existing and future infrastructures. The intent was to install the wellfield in an area with
representative bedrock and oxide mineralization containing an average total copper (TCu) grade based on the BHP geology and resource model completed in 1997. BHP elected to avoid the
complexities imposed by siting the field test above the underground workings, in a major fault zone,
or on Arizona State Mineral Lease land. No disturbance to the North Canal was allowed.
The selected site was conveniently located near an existing water well (WW-4) and nearby electrical lines. It was inconveniently located south of a large, producing irrigation well (BIA-10B) that was
not controlled by BHP and that would cycle on at 1,500 gpm with no notice. The chosen site was
west of the area planned for construction of the future evaporation ponds and would have been integrated into future ISR operations had the project been continued. The 7 acre pond that was
constructed to support the field test was moved north relative to the location specified in the
preliminary engineering designs to avoid disturbing Hohokam cultural features.
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2 Geology The sections below provide an overview of the deposit geology (Section 2.1), drilling methods and
downhole geophysical tools used within the BHP field test area (Sections 2.2.1 and 2.2.2), the
geology logging, sampling, and assaying methods (Sections 2.2.3 and 2.2.4), and the preparation of a geology model and resource estimate in 2010 for the field test (Section 2.3). Conclusions and
recommendations related to the proposed Curis Production Test Facility (PTF) are found in Sections
2.4 and 2.5.
2.1 Deposit Geology and Mineralogy
The Florence porphyry copper deposit formed when numerous Laramide-age dike swarms of
granodiorite porphyry intruded Proterozoic quartz monzonite near Poston Butte (see geologic plan
map in Figure 2-1 and cross sections in Figure 2-2 and Figure 2-3). The dike swarm strikes E-W to
N75-80ºE and dips steeply to the south. The dike swarms may have been fed by a larger intrusive mass at depth that has not been identified to date. Hydrothermal solutions associated with the
intrusive dikes altered the host rock and deposited copper and iron sulfide minerals in disseminations
and thin quartz-sulfide veinlets. Hydrothermal alteration and copper mineralization were most intense along the edges and flanks of the dike swarms and intrusive mass.
The region was later faulted and much of the Florence deposit was isolated as a horst block. This
horst block, as well as the downthrown fault blocks to the west, was exposed to weathering, intense fracturing, and erosion. The center of the deposit was eventually eroded to a gently undulating
topographic surface while a deep basin formed to the west.
Fluctuations occurred in the water table level over time, and the rock was exposed to oxygen. The
iron and copper sulfide minerals were naturally dissolved by naturally formed acids and were remobilized along fractures and redeposited, generally at a lower elevation. The copper sulfide
minerals in the oxidized zone above the water table were converted to copper silicates and copper
oxides, such as chrysocolla and tenorite. Enriched supergene copper minerals such as chalcocite, minor native copper and cuprite are present at a thin, partially oxidized transitional zone above the
top of the sulfide zone. A majority of the copper oxide mineralization is located along fracture
surfaces, but chrysocolla and copper-bearing clay minerals also replace clay-altered feldspar crystals located within the granodiorite porphyry and quartz monzonite. A barren or low-grade zone,
dominated by iron/manganese oxides and clay minerals, caps some portions of the top of bedrock
especially in the western portion of the deposit above the Sidewinder fault. The thickness of the
oxide mineralized zone ranges from 100 to 1,200 feet, with an average thickness of around 400 feet.
The bedrock units have been covered by an average of 350 feet of Tertiary-Quaternary gravels, fines,
and alluvium. These overburden units are flat lying and rest unconformably on the erosion surfaces.
The Whitetail Conglomerate overlies the porphyry deposit in the deep graben to the west. The Whitetail is described as a poorly to moderately indurated, poorly sorted conglomerate composed of
angular and sub-angular igneous pebbles in a brown arkosic matrix (Nason and others, 1983).
Overlying the Whitetail Conglomerate is a poorly indurated, poorly sorted terrestrial deposit
consisting of pebbles and cobbles and commonly, volcanic clasts and basalt flows. This formation may be correlative with the Gila Conglomerate some 30 miles east of Florence. Within the
conglomerate is a flat-lying, aerially extensive clay layer with a palynological age of Pliocene. The
layer is typically 20 to 30 feet thick and occurs 60 to 70 feet above the present bedrock surface. Aquifer testing has demonstrated that this clay layer acts as an aquitard between the bedrock aquifer
below and the overburden aquifer above. Photos of drill core examples of the rock and
mineralization types are shown in Figure 2-4.
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2.2 Geologic Characterization of Field Test Area
The sections below provide a summary of the methods used by BHP to characterize the field test
area prior to the leaching phase. SRK reviewed the available data and prepared cross sections and a detailed three-dimensional digital model to provide the framework to understand the results of
aquifer tests and the ISR results.
2.2.1 Summary of Drilling Methods
The 26 holes in and near the leach test area were drilled by more than one contractor using a
combination of mud rotary, diamond drill core, and reverse circulation (RC) as described in Table
2-1. The mud rotary drilling was performed by Stewart Brothers Drilling of Milan, New Mexico. The core and some RC drilling were performed by Boyles Brothers/Layne Christensen of Chandler,
Arizona. The majority of the RC drilling was performed by Lang Exploratory Drilling of Salt Lake
City. All the historic Conoco and Magma holes in the vicinity are diamond core (cored from a few feet above bedrock), as are BHP-1 through BHP-5. All BHP holes were drilled using mud rotary
methods through the basin-fill units until they reached 40 feet below the top of bedrock. The
remaining holes (BHP-6 through BHP-13) were drilled with reverse circulation methods in bedrock,
with the exception of limited intervals where mud rotary was required to ensure borehole stability. Chemical monitor wells CH-1 and CH-2 were drilled by rotary methods.
Mud rotary methods were avoided in the bedrock portion of the injection and recovery wells to
ensure that the fractures did not become plugged with bentonite and other fine-grained mineral residues. The borehole development techniques remove most, but not all, of the mud cake on the
borehole wall. Fine-grain residual mud was viewed to have the potential to reduce the formation
permeability if not completely removed. In addition, the rotary samples were not viewed to be
reliable samples for assaying.
The borehole diameters allowed the recovery of NX/NQ or HX/HQ-diameter core with the exception
of BHP-2, which is a 6-in diameter hole. The diamond drill portions of the NX and HX holes were
later reamed using RC methods to allow well installation. Well development washed any residual drilling fluids from the well. Practice and a good touch was needed during well development phase
to avoid formation damage as was experienced in BHP-1; the heavily fractured bedrock produced a
hole approximately 3-ft in diameter during the swabbing and development of the hole to remove drilling fluids.
The time to drill and install the first five wells (BHP-1 through BHP-5) was 128 days including
drilling, reaming, well installation, and integrity testing. Three drill rigs operating in tight space
requirements were used initially thereafter decreasing to one rig at the conclusion of well development. The drilling schedule was on a 24-hr, continuous schedule. Rotary drilling and well
installation, and cementing in the basin-fill and top 40 ft of bedrock took approximately 8 days per
well; RC drilling and well installation took approximately 6 days. A detailed description of drilling and installation of the 5-spot is presented in Table 2-2.
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Figure 2-1 Geology plan map at 700 ft elevation above mean sea level
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Figure 2-2 East-west geology cross section 744870N looking north
Figure 2-3 North-south geology cross section 649500E looking east
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Table 2-1 Summary of drilling method and downhole surveys
Drill hole Date drilled Depth (ft.)
Drill type Downhole surveys Other surveys
BHP-1 Magma 1996 830 Rotary 0-340'; HX Core
340-830'
Sperry Sun Dips and
Azimuths
Gamma Ray-Neutron,
Cement Bond, Televiewer
BHP-1 BHP 1997 830 RC/Ream Sperry Sun and Est. Dips and Azimuths
BHP-2 Magma 1996 894 Rotary 0-345'; 6" Core
345-496'; NX Core 496-894'
Sperry Sun Dips and
Azimuths
Gamma Ray-Neutron,
Sonic-VDL, Televiewer
BHP-2 BHP 1997 894 RC/Ream None HydroPhysical Log
BHP-3 Magma 1996 872.5 Rotary 0-340'; HX Core
340-872.5'
Sperry Sun Dips and
Azimuths
Gamma Ray-Neutron,
Sonic-VDL, Televiewer
BHP-3 BHP 1997 872.5 RC/Ream None HydroPhysical Log
BHP-4 Magma 1996 834 Rotary 0-430'; HX Core 430-834'
Sperry Sun Dips and Azimuths
Gamma Ray-Neutron, Sonic-VDL, Televiewer
BHP-4 BHP 1997 834 RC/Ream None HydroPhysical Log
BHP-5 BHP 1997 798 Rotary 0-403'; RC 403-798'
None Cement Bond Log, Colog HydroPhysical
Log
BHP-6 BHP 1997 820 Rotary 0-415'; RC 415-820'
Totco and Est. Dips; Sperry Sun and Est.
Azimuths
Gamma Ray-Neutron
BHP-7 BHP 1997 810 Rotary 0-415'; RC 415-810'
Totco and Est. Dips; Sperry Sun and Est.
Azimuths
Gamma Ray-Neutron
BHP-8 BHP 1997 790 Rotary 0-415'; RC 415-790'
Totco and Est. Dips; Sperry Sun and Est.
Azimuths
Gamma Ray-Neutron
BHP-9 BHP 1997 850 Rotary 0-415'; RC 415-850'
Totco and Est. Dips; Sperry Sun and Est.
Azimuths
Gamma Ray-Neutron
BHP-10 BHP 1997 840 Rotary 0-406'; RC 680-
840'
Totco and Est. Dips;
Est. Azimuths
Gamma Ray-Neutron
BHP-11 BHP 1997 805 Rotary 0-405'; RC 405-805'
Welenco to TD Gamma Ray-Neutron
BHP-12 BHP 1997 770 Rotary 0-405; RC 405-770'
Welenco to TD Gamma Ray-Neutron
BHP-13 BHP 1997 840 Rotary 0-405; RC 405-
840'
Welenco to TD Gamma Ray-Neutron
CH1 BHP 1997 789 Rotary Welenco to TD Gamma Ray-Neutron
CH2 BHP 1997 775 Rotary Welenco to TD Gamma Ray-Neutron
OWB1 BHP 1997 830 Rotary 0-425'; 760-830'
RC 425-760'
Welenco to TD Gamma Ray-Neutron
OWB2 BHP 1997 225 Rotary Totco Dips; Est. Azim. None
OWB3 BHP 1997 820 Rotary 0-425', RC 425-820'
Totco and Est. Dips; Est. Azim.
Gamma Ray-Neutron
OWB4 BHP 1997 755 Rotary 0-415'; RC 415-755'
Totco and Est. Dips; Est. Azim.
Gamma Ray-Neutron
OWB5 BHP 1997 765 Rotary 0-425'; RC 425-
765'
Totco, SureShot, Est
Dips; Sperry Sun and Est. Azim.
Gamma Ray-Neutron
OWB6 BHP 1997 925 Rotary 0-425'; RC 425-925'
Totco Dips; SureShot and Est. Azim.
Gamma Ray-Neutron
MCC427 Magma1993 Rotary 0-366'; NX Core
366-833
Welenco to TD Gamma Ray-Neutron,
Sonic-VDL, Televiewer, HydroPhysical Log
MCC524 Magma 1993 1034 Rotary 0-320'; NX Core
320-1024'
Estimated Dips and
Azimuths
None
MCC524 BHP 1997 410 Rotary 0-410 None Screened 320-340'
MCC534 Magma1994 900 Rotary 0-260'; 6" Core 260-900'
Welenco to TD `
Source: BHP, 1997a
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Table 2-2 Development schedule for 5-spot drillholes, July-November 1996
From To Days Well ID
Notes
8-Jul 10-Jul 2 BHP3 Mud rotary (5 7/8 inches) to a total depth of 340 feet. Install 4 in. steel casing
10-Jul 12-Jul 2 BHP2 Mud rotary (9 7/8 inches) to a total depth of 345 f.
10-Jul 16-Jul 6 BHP3 Drill HX core to a total depth of 872.5 feet
12-Jul 16-Jul 4 BHP2 Open hole to 12 ¼ inches to a total depth of 345 ft. Install 8-in steel casing
17-Jul 19-Jul 2 BHP4 Mud rotary (5 7/8 inches) to a total depth of 340 ft. Install 4-in steel casing
22-Jul 24-Jul 2 BHP1 Mud rotary (5 7/8 inches) to a total depth of 340 feet. Install 4-in steel casing
23-Jul 27-Jul 4 BHP4 Drill HX core to a total depth of 834 ft
25-Jul 2-Aug 7 BHP2 Drill 6 inch core to a total depth of 496 ft
28-Jul 1-Aug 3 BHP1 Drill HX core to a total depth of 830 ft
6-Aug 7-Aug 1 Pulled 4-in steel casing from BHP1, BHP3, and BHP 4 then installed casing in BHP2
8-Aug 20-Aug 12 BHP2 Drill HX core to a total depth of 894 ft.
13-Aug 15-Aug 2 Schramm standing by
16-Aug 19-Aug 3 Install 21 ft of conductor casing in BHP1, BHP3, BHP4 and BHP5
20-Aug 21-Aug 1 Schramm standing by
27-Aug 28-Aug 1 BHP4 Reaming hole to 12 inches. Stopped at 380 ft
28-Aug 31-Aug 3 BHP2 COLOG conducting hydrophysical tests
29-Aug 30-Aug 1 Stand by and pull 8-inch casing from BHP2
4-Sep 10-Sep 6 BHP4 Finishing reaming hole to a total depth of 403 feet. Cement 8 inch PVC.
11-Sep 12-Sep 1 BHP3 Install 21 ft conductor casing and ream 12-in hole to 408 ft
12-Sep 16-Sep 4 BHP3 Ream 12-in hole to 403 ft.
17-Sep 19-Sep 2 BHP1 Ream 12-in hole to 403 ft.
19-Sep 24-Sep 5 BHP2 Install and cement 8 inch PVC annulus, wash out weighted mud
23-Sep 1-Oct 8 BHP5 Mud rotary to 403 ft then install and cement 8-in PVC
1-Oct 4-Oct 3 BHP3 Install 8-in PVC and cement annulus
4-Oct 8-Oct 4 BHP1 Install 8-in PVC and cement annulus
8-Oct 10-Oct 2 Tremie all 5 holes. Convert rig to reverse circulation set-up
14-Oct 22-Oct 8 BHP1 Attempted to install 4-in PVC to 830 ft, not possible so moved rig
22-Oct 28-Oct 6 BHP5 Installed 4-in PVC to 776 ft
28-Oct 1-Nov 3 BHP4 Install 4-in PVC to 742 ft
2-Nov 8-Nov 6 BHP1 Install 1 ½ inch PVC through RC rods to 720 ft
19-Nov 23-Nov 4 BHP3 Install 1 ½ inch PVC through RC rods to 860 ft
23-Nov 26-Nov 3 BHP2 Install 4 inch PVC to 770 ft. Drillers finished.
27-Nov 30-Nov 3 Develop wells: pour pads, install pumps, purge wells, install 4 by 6 adapters
29-Nov 3-Dec 4 COLOG conducting hydrophysical tests on BHP5, BHP4, then BHP2
Total Days
128
Source: BHP drill geology log files
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Notes: BHP-1 Chrysocolla mineralization in fractured monzonite (Yqm), 0.44 %TCu, 0.40 %ASCu, Metzone=2 (Mixed), FRACI=5 (>15
fx/ft), Scale in cm and in units is at top of core box.
BHP-2 Contact of Lower cemented conglomerate overlying the Yqm, 6-in core; one half of the 5-ft long core box is shown.
BHP-3 Tgdp dike in contact w. Yqm. Chrysocolla mineralization is concentrated in the Tgdp in this interval. No core recovery in 4-ft
interval from 510-514’; 0.50%TCu, 0.35%TCu;
BHP-4 Low-grade, iron-stained Yqm, 0.11 %TCu, 0.03 %ASCu, Metzone=2, FRACI=2 (6-10 fx/ft)
Figure 2-4 Selected core photos of BHP-1 through BHP-4
2.2.2 Downhole Geophysical Methods and Data Interpretation
Several downhole geophysical techniques were used by Magma during exploration drilling program; the geophysical surveying services were provided by Welenco (now Southwest Geophysical) of
Gilbert, Arizona. BHP ranked the data acquired from each type of downhole survey according its
usefulness in understanding the character of the rocks in the field test area or necessity in supporting
the well construction activities. The downhole survey tools ultimately used for the field test drilling program included:
Caliper – measures borehole diameter and indicates where washout zones occur;
Cement bond log – sonic tool that detects the bond of cement to the casing and formation;
Gamma ray-neutron – measures the naturally occurring gamma radiation of the borehole wall. It
helped to identify or confirm the contracts for the clay unit, which contains potassium isotopes,
and the top of bedrock; and
Acoustic borehole televiewer (BHTV) – a sonic tool that generates an acoustic image of the
borehole wall, from which the dip angle and azimuths of structures can be measured
The gamma-neutron logs were essential in confirming the geologic contacts especially in the basin-fill formations where cuttings were all that was available to delineate the geologic contacts. The
BHTV was used to correlate structures between drillholes, as detailed in Section 2.3.1 below. Other
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tested methods (gamma ray, spectral gamma ray, sonic/variable density log, spinner surveys,
induction, and heat pulse) did not add sufficient value to warrant continued use.
2.2.3 Geologic, Structural, and Mineralogy Logging Methods
The detail of logging for rock types, structure, and mineralogy varied according to drilling method as described below. Costs for the field test program are provided where documentation was available.
Rotary
Rotary drilling was performed by Stewart Brothers and cost $55/ft for 14-in surface borings and $26.50/ft for 10 5/8-in diameter boreholes. The average cost per foot including materials (mud,
surface casing, PVC) was $59.60. Mud rotary drilling uses a fairly viscous fluid (primarily bentonite
and water), injected through the drill pipe, to circulate cuttings out of the drill hole. The drill method helped keep the boreholes open in the basin-fill formations (and in washout zones in bedrock).
Several biases occurred as cuttings and mud travel up the drill hole between the string of drill pipe
and the wall of the drill hole. These included:
Overlap of material from adjacent samples caused by incomplete removal of the sample,
Contamination caused by caving or tear out of the borehole wall,
Concentration of coarse-size particles in the sample collection trough and fines in the
recirculation pit or tank,
Travel lag time in deep holes (minor problem in holes less than 1,500 feet), and
Cutting size bias when sieving/washing the sample prior to logging (fines washed through the
sieve).
For all these reasons, the rotary holes were sampled and logged at Florence but were not assayed. Logging of the rotary portion of the holes consisted of noting color, grain size, rounding/angularity,
the dominant grain composition, and the percentages of silt, sand, and gravel in the samples of the
basin-fill formations. A kitchen sieve and bucket of water were typically used, which allowed everything finer than the ~1mm sieve opening to be washed away. This was not a problem when
drilling in bedrock as the fines usually have the same constituents as the coarse material. When
drilling sediment, however, the fines provide information about the conglomerate matrix or overall composition (silt, clay unit) and may be distinct from the clast composition.
It was not possible or practical to correct some or all of these biases, so the most efficient method of
logging was to note them, and try to use other observations to infer the scale of the bias. Lithology
changes were noted based on new rock types seen in the sample rather than waiting for cuttings from the previous unit to disappear, as contamination could mask lithology changes for several tens of
feet.
Another useful observation was to look at the color and consistency of the sample before it was washed, in order to estimate silt and clay content. Silty formations tended to make the bentonite
mud (i.e. drilling fluid) very brown and opaque, whereas clean bentonite mud is a very pale tan color
and slightly translucent. Cuttings from the Clay unit (also known as the middle fine-grained unit) or more clay-rich intervals tended to ball up and behave like larger clasts. Even if there is a gross
sampling bias, the presence of the Clay unit may be noted from plastic balls of clay showing up in
the sample.
Structural measurements were a challenge in the basin-fill formations and bedrock owing to lack of detail seen in rotary chips, but the geologists did detect the presence of post-deposit faults seen in
bedrock within the top 40 feet of bedrock and the basin-fill formations immediately overlying the top
of the eroded bedrock. Faults in bedrock were detected in cuttings by the sudden appearance of clay (typically red colored) or dominance of clay in an interval well below the Clay unit with possible
changes in drill speed.
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Diamond Drill Core
Diamond drill core was intended to be used in the bedrock in BHP-1 through BHP-5 for what was envisioned to be the original injection/recovery 5-spot cell. Ultimately, HX core was drilled in BHP-
1, BHP-3, and BHP-4; 6-in core was drilled in BHP-2. Significantly greater detail could be gained with diamond drill core but the downsides included significantly higher cost per foot and lower
drilling speed. The average cost per ft was $33.50.
After cleaning the core drilled for the BHP field test, the core was photographed using a 35mm
camera attached to a photography stand at a set distance above the core box. Note for the future…make sure the photographer has good eyesight and can focus the camera! After slide
development, some sets of photos were discovered to be out of focus, but the core had already been
cut/split and sent for assaying. Out-of-focus slides should not be such a problem with the instant feedback provided by a digital camera. Footages were marked with permanent marker pens in 1-foot
increments on the drill core to tally overall core recovery in each interval and to assess the exact
location of any core lost. The marked intervals then were used as standard footages geology and
geotechnical logging, fracture logging, sampling, and assaying purposes.
All holes were logged for rock type, mineral percentages, fracture intensity, and metallurgical zone
in accordance with the standard procedures used previously (BHP, 1997a; Section 3.5) and following
coding conventions previously developed by Conoco. Rigorous structural logging occurred including recording percent recovery, rock quality designation (RQD), and depth below surface of
fractures and faults. Goniometers and protractors were used to measure dip angles in NX, HX, and
six-inch core. Dip angles were measured parallel to the core axis and then subtracted from 90° to convert them to dip angles perpendicular to the core axis (true dip). No adjustments were made for
the 0.5 to 2.0 degrees of downhole deviation. The data were recorded on hard copy, entered into
Excel, checked by a second person, and then ultimately imported into the MineSight drillhole
database.
Data collected for the fracture mineralogy studies included the depth of the fracture, the fracture
angle measured parallel to the core axis, and mineral coatings. The mineral coatings in the fracture
mineralogy study included the following minerals: hematite, goethite, jarosite, calcite, chlorite, biotite, chalcopyrite, pyrite, gypsum, clay, Cu-clay, chrysocolla, and tenorite. The minerals were
entered as abundances relative to each other as there was no reliable way to estimate actual
percentages. The fracture data were then entered into a spreadsheet, and a hard copy filed in the appropriate geological log. Plots and graphs were prepared showing the vertical distribution and
intensity of various mineral assemblages in the drillhole and the correlation of various mineralogy
assemblages to fracture dips (sorted into 5-degree and 10-degree bins). The elevation of the
fractures above sea level was calculated by subtracting the footage (depth below surface) from the measured or estimated elevation of ground surface next to the well. The mineralogy depth and dip
angle data was later correlated to the fracture azimuth and dip data set digitized from the acoustic
borehole televiewer output.
Reverse Circulation
RC drilling methods were used to drill injection wells BHP-6 through BHP-8 and a number of the
other recovery and observation wells. The cost for RC drilling by Lang Exploratory Drilling of a 6 ¼-inch diameter borehole was an average of $23.60/ft with a maximum of $30.65/ft. Because this
drill method uses compressed air to lift the sample and any fluids out of the hole, often at greater
speeds than with conventional mud rotary drilling, there is less likelihood of segregation errors at the sample collection stage. Contamination is less than with mud rotary because the sample does not
come in contact with the walls of the drill hole as it travels to the surface. Local contamination from
one sample to the next (i.e. “smearing”) can also be considerable, but depends almost entirely on the
diligence of the driller in clearing all of a sample before drilling the next interval. Large amounts of
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ground water (>50 gpm), and also the fairly light viscosity mud used in RC drilling tend to amplify
these inaccuracies.
The samples collected from RC drilling were judged to be of good quality for sampling and assaying
purposes but less detailed data were generated. Drilling difficulties associated with RC methods
included greater downhole deviation from vertical and a few significant hole washouts that required switching to mud rotary methods for short intervals.
2.2.4 Sampling and Analysis Methods
Sample intervals in RC drill holes adhered to a 10-foot sample interval. Sample intervals in core holes were 10 ft in length for continuous stretches of uniform rock type. The sample lengths of
selected core intervals could vary from 1 to 11 feet in length based on changes in rock type or
position with respect to model bench elevations. The goal was to ensure that one rock type was coded per assay interval for ease of statistical calculations (rock type, grade, fracture intensity, and
Metzone). A 1-ft interval, for example would only have been delineated if a significant change in
rock type to a thin andesite or diabase dike was encountered; the andesite or diabase would not have
been composited with Tgdp or monzonite.
Additionally, the site geologists knew that after logging and assaying were completed, the 10-ft
assay intervals would be composited into 50-ft bench composites that matched the bench toes/crests
in elevation above mean sea level (amsl). Shorter or longer core intervals would be generated so that the sample intervals in the near vertical holes would match the 10-ft increments that would fall
within the 50-foot bench height elevations (amsl).
Actlabs-Skyline (now Skyline Assayers and Laboratories) of Tucson was the sole laboratory for analyzing the RC chips and diamond drill core. A hydraulic splitter and diamond-blade saw were
used to divide the core samples into equal portions – one of which was sent to the lab. The core
samples were bagged and tagged by on-site technicians. Splits (A and B) from the same interval
were taken on every 20th sample. Pulps of known site-specific standards at seven grade ranges were prepared in pulp envelopes and inserted into the sampling stream for both core and RC samples. The
pulps were weighed before and after shipment to ensure the sample was actually assayed by Skyline.
Samples were analyzed for %TCu and %ASCu using a standard method. The site geologists reviewed the results against what was seen in the core and compared the QA/QC results against the
list of acceptable deviations for each standard. If there were no QA/QC problems, the assay results
were posted to the drill log; QA/QC problems were infrequent and quickly resolved with Skyline.
2.3 Preparation of Geology Model for Field Test Area
BHP was in process of preparing geology cross sections and a digital geology model using MineSight software when the staff was laid off, so the post-drilling model was never finalized.
Using the geologic logs for the 19 leach test holes and 7 nearby Conoco and Magma exploration
drillholes, SRK generated a 3-D model of the subsurface geology of the BHP field test area. MineSight software was used for the 3-D geology modeling; Vulcan software was used to prepare
the updated resource estimate.
2.3.1 Structure Compilation
The only opportunity to inspect and map the structures visually at Florence was provided during the
development of the Conoco underground pilot mine. Geologic mapping performed by Conoco
during the operation of their pilot mine gives a more complete picture of the structural fabric of the rock than vertical drillholes are able to provide. BHP reviewed the Conoco maps and divided the
faults observed in the pilot mine into groupings based on their strike and dip directions (Maher,
1999). This study showed that E-NE striking faults with steep dips are the most common orientations recorded in the pilot underground mine while the N-NW striking faults were the most
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common structures delineated in the Magma and BHP deposit-scale geology models. Because all
drilling conducted in the Florence deposit is vertical, steep structures such as the ones physically measured in the Conoco pilot mine will be under-represented in drill core. Maher speculated that
one or more structures with this orientation may have influenced the hydraulic connection between
wells in the field test – especially between the injection wells and BHP-5.
Borehole televiewer logs were available for four of the field test boreholes (BHP-1, BHP-2, BHP-3,
and BHP-4). The televiewer logs provide an acoustic image of the borehole wall that highlights
zones of fractured rock as well as the aperture width and orientation of individual fractures and faults. The fractures and faults were digitized by BHP technicians using software provided by
Welenco. The digitized output includes the downhole depth of each digitized feature, the sinusoidal
trace of the feature, and the dip angle and dip azimuth of each digitized joint or fault. The technician
did the on-screen digitizing at the same time the core was being logged so had good opportunity to “ground truth” the digitized features.
There was good correlation in the downhole depths of fractures measured in drill core versus the
depths measured by televiewer with the exception of core loss zones where an assumption had to be made by the geologist on the actual depth of core loss. Dip angles measured in drill core were
typically within 2 degrees of the angles in the digitized fracture. The digital data set of acoustic
borehole televiewer fractures was correlated to the Excel spreadsheets of depths, dip angles, and
fracture mineralogy recorded in drill core. This was done to assess if copper oxide mineralization as recorded as fracture mineralogy had a preferred dip orientation in 5-degree, 10-degree, and 20-
degree bins. Copper oxide mineralization was recorded on fractures dipping in all directions but the
mode was in a westerly direction – reflecting the importance of Basin and Range structures in remobilizing the copper. The digitized measurements were also correlated with the geologists’ log
to provide actual azimuth and dip orientations to significant fault and fracture zones.
SRK reviewed the output from the acoustic borehole data and compared the measurements to those recorded in the geology logs to identify the possible presence of clay-rich fault gouge zones that
could serve as a barrier to solution flow. Alternatively, broken rock contacts or fault breccia zones
could have acted as high-conductivity pathways. A compilation was made of the structural
orientations of significant fault breccia and clay-rich zones, which were brought into MineSight to see if these structures could be correlated between drillholes.
The large number and variability of the measured structures with actual dip azimuths and dip angles
made correlation difficult. In many cases, the extrapolation of a measured structure in one drillhole would coincide with the down-hole depth of a measured structure in another drillhole, but the strike
and dip of the two structures would not match within reasonable expectations.
Two structures (here named the Coachwhip fault and Tarantula fault) were identified that were
traceable between several holes in the leach test area. While televiewer logs were not available for 15 of the 19 holes, correlation was possible using the geologic logs where geologists noted the
presence of a fault zone based on chip logging. The magnitude and direction of the displacements
along these two faults are unknown. For illustrative purposes the Tarantula fault (N35°E, 75°NW) crosscuts the Coachwhip fault (N63°E, 75°SE) and appears to show 10 ft of dip-slip motion. The
SRK geology model does not incorporate any fault displacements because the amount of offset
cannot be determined.
2.3.2 Detailed Lithologic Model
Using the drillhole intercepts, SRK generated a detailed 3-D lithologic model. The lithology was
simplified into Tertiary basin-fill formation, undifferentiated Tertiary granodiorite porphyry (mineralizing intrusion), and Proterozoic quartz monzonite porphyry (host rock). Other
volumetrically minor units such as Proterozoic diabase were not modeled.
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For the purpose of the model, the corehole logs were assumed to be the most reliable. Where holes
with different drilling methods were in very close proximity, the logged geology would not typically agree. During the reaming of BHP-1, for example, several cave-ins occurred that generated sample
contamination in the RC chips – making the comparison to the same core interval meaningless. In
these cases, the hole drilled with the more detailed and reliable sampling method was used, and the other disregarded.
The model boundary was chosen to extend 100 ft beyond the field test on all four sides. Within this
model boundary, three rectilinear grid sets (N-S, E-W, and Plan) were constructed on 50’ intervals, for the construction of 2-D polygons representing the lithologic units. Previous work shows that the
porphyry dikes strike about N80°E and dip steeply to the south, so the N-S cross sections were
generated first (Figure 2-6). The plans were drawn next, followed by the E-W long sections (Error!
Reference source not found.). Once all three sets of polygons were completed, a solid representing the porphyry dikes was generated using the polygons (see perspective views in Figure 2-7). Solids
for quartz monzonite porphyry and basin-fill formation were generated by clipping the model
boundary solid against the top of bedrock and the granodiorite porphyry solid.
2.3.3 Summary of the Field Test Area Geology
Globally within the deposit area, quartz monzonite is the dominant rock type (70%). The BHP field
test area, located on the southern edge of the densest concentration of porphyry dikes in the deposit, consists of about 60 percent granodiorite porphyry and 40 percent quartz monzonite porphyry. The
porphyry dikes strike approximately east-west, but are curved and anastamosing bodies that merge at
depth. The dikes dip at about 80° to the south.
The structural geology in the field test area is quite complex. The limitations imposed by the lack of
outcrop and the vertical drillhole orientations make delineation and correlation of fault structures
very difficult. The sheer number and variable orientations of structures noted in the geologic and
borehole televiewer logs attests to the complexity. The rock is very thoroughly and intensely fractured, with innumerable small slips and minor faults. The mineralogy consists of mixed copper
and iron oxides, silicates, and hydroxides.
2.3.4 Mineral Resources of Field Test Area – 2010 Estimate
The geology and assay statistics for the 19 drillholes within the field test area are shown in Table
2-3. The average drillhole grades in the BHP field test area (0.428 to 0.446 %TCu) are relatively
higher than the average grade for the Florence deposit (0.331 %TCu). Additionally, the table presents the ratio of ASCu:TCu grades, and the calculated modes for rock type (drillhole database
code ROCK), metallurgical zone (METZO), fracture intensity (FRACI), copper minerals present on
fracture surfaces (CuOx1), and copper minerals present in altered feldspar sites (CuOx2).
To calculate the resources of the field test area, SRK created solids bounded by the top of bedrock,
the top of sulfide, and the vertical traces of the injection and recovery wells (Figure 2-8). An
additional solid was created for the top 40 ft of bedrock (Bedrock Exclusion Zone) where blank casing was used and little copper extraction was expected to occur. Average %TCu and %ASCu
grades were calculated for the oxide zone excluding the bedrock exclusion zone. The resources
contained in the field test area were calculated using the SRK 2010 resource model and are
summarized in Table 2-4.
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Table 2-3 Drillhole assay statistics for the field test area
Well 1
Top of
Bedrock 2
Top of
Sulfide 2
Interval Length
Avg.
TCu (%)
Avg.
ASCu (%)
ASCU
:TCu Ratio
Rock
Mode 3
METZO Mode
4
FRACI
Mode 5
CuOx
1 Mode 6
CuOx
2 Mode 6
BHP-1 363 808.1 445.1 0.471 0.337 0.715 29 2 5 1 2
BHP-2 368.3 848.6 480.3 0.623 0.363 0.583 21 2 3 2 1
BHP-3 363 800.25 437.25 0.440 0.314 0.714 21 2 2 1 1
BHP-4 362.5 796.4 433.9 0.434 0.291 0.671 21 2 2 0 1
BHP-6 370 820 7 450 0.474 0.364 0.768 29 2 N/A
8 2 2
BHP-7 370 793.9 423.9 0.270 0.191 0.707 31 2 N/A 8 0 0
BHP-8 370 774.5 404.5 0.322 0.244 0.758 21 2 N/A 8 1 3
BHP-9 370 821 451 0.471 0.328 0.694 21 2 N/A 8 1 3
BHP-10 370 819.5 449.5 0.335 0.198 0.591 29 2 N/A 8 1 1
BHP-11 360 797 437 0.603 0.459 0.761 29 2 N/A 8 1 2
BHP-12 370 745.7 375.7 0.309 0.250 0.809 31 2 N/A 8 1 1
BHP-13 370 803.5 433.5 0.465 0.335 0.720 21 2 N/A 8 1 2
OWB-1 370 810.5 440.5 0.369 0.255 0.691 31 2 N/A 8 0 4
OWB-3 370 795.3 425.3 0.295 0.201 0.681 21 2 N/A 8 1 1
OWB-4 370 728 358 0.417 0.312 0.748 29 2 N/A 8 3 3
OWB-5 370 765 7 395 0.208 0.132 0.635 21 2 N/A
8 1 1
CH-1 370 789 7 419 0.341 0.243 0.713 21 2 N/A
8 3 0
CH-2 370 775 7 405 0.533 0.418 0.784 21 2 N/A
8 2 2
MCC427 360 761.25 401.25 0.543 0.424 0.781 21 2 3 2 1
1 – Wells BHP-5, OWB-2, and MCC534 are within the field test area, but no assay data are available
2 – Downhole depths
3 – Rock type 21 = quartz monzonite porphyry (Yqm); 29 = mixed Yqm and Tertiary granodiorite porphyry (Tgdp); 31 = Tgdp
4 – 2 = mixed iron and copper oxides
5 – FRACI code 2 = 5-10 fractures per foot; 3 = 10-15 fractures per foot
6 – 0 = minerals not noted; 1 = <1%; 2 = 1-2%; 3 = 2-5%; 4 = 5-10%
7 – Sulfide zone not intersected; depth given is TD
8 – Rotary/RC holes; no fracture data collected
Table 2-4 Mineral resources in BHP field test area
All Measured Oxide in Bedrock at 0.05% TCu cutoff
Area Tons TCu (%) ASCu (%) lbs TCu lbs ASCu
Within 8 Recovery Wells
1 636,812 0.431 0.310 5,490,000 3,950,000
Within 4 Injection Wells
2 154,063 0.448 0.319 1,380,000 983,000
1 – Recovery wells are BHP-2, 3, 4, 5, 10, 11, 12, and 13
2 – Injection wells are BHP-6, 7, 8, and 9
Source: SRK, February 2010 resource estimation.
Tonnage factor = 12.5 cubic feet per ton
Includes all Oxide material below the top of bedrock excluding the bedrock exclusion zone (top 40’ of bedrock). All mineral resources
within these two areas are classified as “Measured”
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SRK, 2010. Tgdp dike mass (blue) intrudes Yqm (buff) and is crosscut by a number of faults. Cross section lines A-A’ and B-B’ are
shown for reference.
Figure 2-5 Geology plan map through field test area; 700ft amsl
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Figure 2-6 N-S geology section 649370E through field test area looking east (L) and E-W section 744925N through field test area looking north (R)
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3-D depiction from top of bedrock of the three E-W-trending Tgdp dikes (blue) and drillholes in the BHP field test area. Quartz monzonite
(not shown) is the host rock.
Figure 2-7 Perspective views of the Tgdp dikes looking due W, -60 degrees (left) and S45°E, -75 degrees (right)
Source: SRK, 2010. Model blocks are 50’ x 50’ x 50’. Block grade cutoff colors: Blue = >0.2%TCu, Green = >0.3%TCu, Yellow =
>0.4%TCu, Orange = >0.5%TCu, Red = >0.6%TCu. Volume excludes the 40’ bedrock exclusion zone.
Figure 2-8 Plan view of volume of rock within field test designated for resource calculation
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2.4 Conclusions and Lessons Learned
The general geology of the Florence deposits is well understood through drilling data, downhole
geophysical surveys, and the previous physical inspection by Conoco of the geology in the underground pilot mine. The existing geology deposit model is a good conceptual framework to
predict the approximate contacts and types of rocks and mineral zones to be encountered in any
specific area of the deposit and to enable the development of a life-of-mine plan for copper extraction. The fact that the bedrock is overlain by more than 370 ft of basin-fill formations and is
not available for additional physical inspection, in the usual sense, will always provide a measure of
difficulty and uncertainty in formulating detailed hydrogeological and structural models – especially
in predicting the detailed geology and rock properties at the 100-ft 5-spot production scale.
Vertical exploration drillholes spaced on a 250-ft, E -W oriented grid provide adequate definition for
resource estimation purposes, but have a reduced probability of intercepting steeply dipping
structures such as the E-NE striking 70 degree structures found at Florence. These structures were utilized by the Tertiary-Laramide granodiorite dikes to intrude and fracture the Precambrian quartz
monzonite host rock, and deposit quartz-chalcopyrite-pyrite-molybdenite veinlets, disseminated
grains, and fracture coatings. The historic structural fabric and Tgdp dikes are responsible for the
principal direction of E-NE anisotropy noted in the spatial distribution of mineralization and the responses seen in various aquifer tests. The geology model incorporates both E-NE and N-NW
features including the orientation of the porphyry dike swarm and the post-mineralization Basin-and-
Range faults. The model, however, is biased towards the identification of these later N-NW striking, moderately dipping faults, because they have a greater chance to be correlated from one drillhole to
the next. The Tertiary extensional period and Basin-and-Range faulting are responsible for the
intense fracturing, oxidation, and remobilization of former copper sulfide minerals to form a 40- to 1,035-ft thick copper oxide/silicate-bearing Oxide zone.
On the scale of the BHP field test, the intricacy and finely divided nature of the Tgdp dikes was
surprising even though the presence of thin dikes was previously known. Three major E-W striking,
south-dipping dikes crosscut the test area and coalesced at depth to form two main porphyry bodies. These dikes pinch and swell, and have variably-sized protuberances at irregular intervals. While the
overall trend of the dikes is approximately E-W, on a more detailed level the contacts commonly
deviate from this trend. The Tgdp dikes may also locally contain large xenoliths or intrusion breccia lenses of Yqm.
2.5 Recommendations for New Field Test
Presented below are comments and recommendations related to the Curis Production Field Test
(PTF) planned to begin in 2011. A work plan to coordinate all geology, hydrology, metallurgical
and operations activities has not yet been developed for the PTF.
2.5.1 Proposed Location of PTF and Associated Surface Disturbance
Two phases of drilling related to the development of the PTF are planned – the timing of the phases will likely overlap in the project schedule. Phase I entails using a rotary drill rig to abandon 10
exploration drillholes and wells as shown on Figure 2-9. Abandonment of historic holes and wells is
designed to close potential pathways to the overlying formations once raffinate injection begins.
Phase II entails using a combination of diamond drill and rotary methods to drill 18 to 24 new wells in a 1.8-acre area south of the BHP field test area. The project site contains areas that are eligible for
listing on the National Register of Historic Places (NRHP). It is Curis’ intent to minimize surface
and subsurface disturbance during any drilling related activities. Surface disturbance is defined as the disturbance occurring in the top 4-6 inches primarily owing to driving-related ground
compaction. Subsurface disturbance is defined to occur in excavated or drilled areas 0 to 10 feet
below the surface.
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During Phase I, new temporary, unimproved roads will be created in the farm field to access the 5
wells and 5 exploration drillholes to be abandoned. Well and drillhole locations O39-O, P39-O, 433MF, and 482MF are within an area eligible for NRHP listing (Site 292). The total estimated
surface disturbance within the NRHP site is 0.48 acres, as shown blue hatching in Figure 2-10. An
access road width of 12 ft was assumed, which was determined by using a drill rig width of 8.5 ft, length of 26 ft, and turning radius of 50 ft. The working disturbance area is estimated to be
approximately 50-ft by 100-ft at each site. The drill will be limited to linear maneuvers (i.e. forward
and backward) within the NRHP site.
The locations of the buried exploration hole casings were surveyed using information in the drill
logs. The top of casing for a typical Conoco exploration hole is buried approximately 3 feet below
ground surface. To date, four of the target casings have been definitively located through the use of
a metal detector. The location of 433MF is known and has been surveyed, but the casing has not yet been identified through use of a metal detector so is likely deeper than three feet. A backhoe with a
2-foot wide bucket will be used to expose the top of casing on all holes. A trench approximately 5-ft
long, 3-ft deep, and 2-ft wide will be excavated, and excavation will stop when the top of casing is exposed. A distinct change in soil color typically appears immediately above and adjacent to the
casing up to 18 in below ground surface; this color change occurs where fill dirt was used to backfill
the top of the cut casing. This change in soil color will be used to assist during the excavation of
433MF. The backhoe will scoop the top 18 inches of soil over the approximate hole location to identify the fill dirt and covered 433MF casing.
Once the top of the casing has been exposed, a piece of 4-in PVC pipe will be inserted over the outer
rim of the casing to keep the boreholes free of dirt, and the trench will be backfilled with the dirt that was temporarily stockpiled. The rig will pull up over the top of the open casing, remove the PVC
pipe, and proceed to enter the hole and abandon it with Type V acid- and sulfate-resistant cement to
within 5 feet below ground surface. Following abandonment, any surface depression remaining above the closed drillhole would be backfilled and the surface regraded by shovel and rake. No
other surface excavations are required.
No subsurface excavations are required to close the five monitor wells. Abandonment of the wells
will involve filling the well casing with Type V cement and removing 19 feet of 12.75-in diameter surface conductor casing. The existing 4 in x 3 ft concrete pad supporting the wellhead vault will
also be removed. The ground immediately above the closed well will be regraded by shovel and
rake.
Phase II drilling is within an 1.8-acre area south of the BHP field test that has been identified to
contain no cultural resources eligible for listing on the NRHP. The estimated extent of surface and
subsurface disturbance related to well abandonment, drilling, and operation of the PTF including a
new pipeline corridor is shown on Figure 2-9. An elevated gravel-topped access spur road will pivot off the previously existing farm and field test roads. A pipeline corridor with a 2-foot deep ditch
lined with high density polyethylene liner will pivot off the existing pipeline corridor as shown in
yellow hatching on Figure 2-9. The approximate locations of the new road spurs, drill site disturbance area, and proposed pipeline corridor are shown in red hatching.
Subsurface disturbance in the top 20 feet includes drilling and installing 12.75-in diameter surface
conductor casing. An aboveground mud tank will be used to support the drill rig during rotary drilling of the top 390 feet. A mud tank is not needed for drilling below this depth. No other
subsurface excavation is needed to complete the drilling activities.
2.5.2 Drilling Methods
SRK recommends that mud rotary methods be used in the basin-fill formations; this drill technique
provides stable drilling conditions and boreholes in unconsolidated basin-fill formations with
virtually no deviation from vertical. Rotary methods may also be appropriate for holes designated as
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observation wells unless the intent is to convert the observations wells to injection or production
wells in the future.
SRK recommends that only core and reverse-circulation drilling methods are used in the bedrock
within the PTF for holes to be assayed. Use of conventional mud rotary methods will preclude the
collection of meaningful assay data, which is essential for detailed determination of the head grade within the PTF. Without assay data, the accuracy of the recovery calculations will diminish. Lastly,
use of mud rotary methods in the bedrock will require extensive swabbing and well development of
rock that is already highly broken, friable, and prone to caving if agitated too greatly. Removing the residual mud is a time-consuming hourly driller’s charge that cannot guarantee all mud will be
removed. The formation porosity needs to be kept intact as long as possible during the test and in
operations, so it is a risk to use a method that can plug the fracture apertures before injection begins.
The reverse circulation method provides better delineation of geology contacts than does mud rotary drilling, but neither methods provides the level of detail achieved in a diamond drill hole. It is
recommended that a minimum of five of the PTF holes are drilled using diamond core methods, and
that the borehole televiewer is used in those holes. Diamond drill core will allow detailed review of rock contacts, fracture mineralogy, and the distribution of copper mineralization. Use of the
borehole televiewer will allow the geologists to correlate logged faults between holes, as was done
previously. As with the BHP holes, a downhole gamma probe should be used to determine the clay
layer and bedrock contacts. The caliper log and cement bond log are required to assess the success of cementing.
For consistency, all holes should be logged and sampled according to the geology SOPs developed
previously (detailed in Section 3.2.3 above).
2.5.3 Geology of Curis PTF
Based on evaluation of available drillhole data and the deposit geology model built in the 1990s by
BHP, the geology of the proposed Curis PTF will likely be less complicated than that seen in the BHP field test area. The Curis PTF area appears to contain approximately 75 to 80 percent Yqm, a
typical representation of the Florence deposit. The bedrock is overlain by approximately 375 feet of
basin-fill units, similar to that measured elsewhere on the property.
There appears to be four E-W striking Tgdp dikes in the proposed PTF area as shown in Figure 2-10.
Three sub-parallel, south-dipping dikes are 10-20 feet thick and one north-dipping dike is
approximately 30 feet thick; the latter dike splits off from the southern-most dike in the BHP field test area. In addition to the Tgdp dikes, there are several Tertiary andesite dikes that are
approximately parallel to the E-W striking, south-dipping Tgdp dikes. These andesite dikes appear
to be less than 20 feet in thickness. The BHP model also includes several north-striking dikes of
Precambrian diabase. SRK was unable to identify the drill intercepts from which these interpretations were made and believes they were “modeled in” based on interpretation from
drillholes outside the immediate vicinity of the PTF.
The oxide zone is estimated to be 350 to 450 feet thick in the PTF area. The oxide zone in this area contains mixed copper/iron oxide and silicate minerals and has a representative average grade of
0.45 %TCu and 0.37 %ASCu. Some preferred pathways may be expected to develop parallel to the
dominant E-NE striking sub-vertical Tgdp dikes. Based on nearby drillholes, however, the overall
rock fabric is highly fractured with an estimated fracture intensity of 10-15 fractures/ft.
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Figure 2-9 Proposed location of Curis PTF and associated disturbance
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Figure 2-10 Geology plan map of PTF, 900 ft amsl (upper); E-W geology profile 744600N looking north (left) and N-S geology profile 649250E looking east; (Tgdp is blue, Yqm is buff)
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2.5.4 Logging, Sampling, and Assaying Protocols
The protocols for logging, sampling, and assaying should be reviewed to ensure best current
practices are followed. Protocols are in place and can be transmitted to the field staff to ensure
geological, structural, fracture mineralogy, and geotechnical logging techniques are consistent with previous work. For the PTF activities, logging will likely occur on a combination of hard copy logs
and digital data entry. During operations, logging and data entry activities should consider using
primarily digital logging methods via hand-held computer, bar-coding, and other standardized
formats for instant manipulation and use.
Sampling and assaying protocols were previously in place to ensure high confidence in the integrity
of the analytical results and should be continued during PTF activities. Sample integrity and a good
quality “Head assays” for the injection zone cannot be guaranteed with use of mud rotary drilling. As mentioned previously, the use of mud rotary drilling should be avoided in the injection zone with
the exception that limited mud rotary drilling may be required if hole stability difficulties are
encountered.
Samples collected from mud rotary intervals would be logged but not be sent for assaying owing to potential contamination through co-mingling with the overlying formation. Samples taken with RC
drilling are recommended to adhere to a 10-ft assay interval. Samples taken by diamond drill
methods will generally adhere to a 10-ft assay interval but should honor rock contacts to provide the best statistical correlation of rock type versus grade.
No changes to the methods for analysis of %TCu or %ASCu are recommended without a well-
thought out correlation study using both former and new methods. The only addition would be the analysis of a more complete list of constituents by inductively coupled plasma mass spectrometer
(ICP-MS) methods. Addition of ICP-MS analyses may assist to determine the concentrations of
trace elements that can be environmentally or otherwise significant. The additional analyses could
be performed on each interval or on selected intervals to reduce the cost (every other interval, every 5th or 10th interval, or on a 50-ft composite).
The QA/QC program including duplicate splits and standards was well-developed and robust in
execution. SRK recommends including occasional blanks in the stream to assess the laboratory’s sample preparation techniques and to send a select number to another laboratory for secondary
comparison of results.
Samples of fracture and feldspar-site mineralogy should be collected every 100 ft and analyzed by XRD, to confirm the mineralogy of the copper minerals and associated gangue minerals. Chip and
core samples are also planned to be used for additional bottle roll or column tests to assess copper
recovery and rate of recovery based on laboratory conditions, acid consumption. The samples may
also be used to assess the effectiveness of various pre-treatments for improving extraction and rinsing amendments to assess reclamation timing, cost, and effectiveness.
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3 Design of Test Facilities The following sections summarize the design of the BHP test facilities. The facilities include the
wellfield, well construction and well head infrastructure, and the general facilities (tank farm, control
room, pipeline, and evaporation pond).
The field test as previously mentioned was designed with three objectives. First, the test was
conducted to demonstrate that the wellfield could be operated in a manner that met the
environmental regulations. Second, the test was required to understand the ISR process, primarily the copper recovery curve as a function of time – this was required to develop operating and capital
costs and to declare reserves. The test was also performed to prove the capability of reclamation.
Twenty-one wells were drilled with a spacing of 50 feet (Figure 3-1, OWB-6 is not shown). The original design was to inject in BHP-1 and recover in wells BHP-2 through BHP-5. Hole stability
problems with certain intervals in BHP-1 made it undesirable to use BHP-1 as a long-duration
injection well. The layout was revised to inject raffinate in BHP-6 through BHP-9, with a fence of
outer recovery wells. The spacing of the wells was determined after a review and simulation of multiple alternatives such as 7-spot, 9-spot, line-drive, staggered line drive, and other configurations.
Figure 3-1 Field test layout
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3.1 Well Construction Design
There were three types of well designs for the pilot field test as shown on Figure 3-1. A description
of the injection and recovery wells (BHP-1 through BHP-13), the chemical monitoring wells (CH-1 and CH-2), and six observation wells (OWB-1 through OWB-6) is presented in Sections 3.1.1
through 3.1.3. Descriptions of the cementing process for the borehole annulus and the mechanical
integrity tests are presented in Section 3.1.4 and 3.1.5, respectively. The wellhead design for the BHP injection and pumping wells is presented in Section 3.1.6.
3.1.1 Injection and Recovery Wells
The 13 BHP wells have an identical design to allow them to be used as either recovery or injection wells. The uniwell construction design for the injection and recovery wells is shown on Figure 3-2.
The holes were drilled using mud rotary methods to the overburden bedrock contact between 340
and 370 feet below ground surface (bgs). In wells BHP-1 through BHP-4, the remainder of the hole in excess of 800 ft was drilled with 3-inch inner diameter (ID) HX core (6-inch core for BHP-2)
down through the lower basin-fill, oxide zone, and into the sulfide zone. The holes were reamed out
with reverse circulation methods. BHP-5 through BHP-13 were drilled to approximately 20 ft into
the sulfide zone by reverse circulation methods to approximately 800 ft (Table 3-1).
BHP staff developed a general well construction plan, but some field changes were made as needed
when difficulties were encountered in the individual holes. The well construction followed EPA
specifications including the general pattern listed below.
Steel surface casing (12 ¼” dia.) was installed in the top 20 ft and cemented with Type V acid-
resistant and sulfate-resistant cement in a 16-in diameter borehole.
A 12 ¼-inch diameter hole was drilled to 40 ft below the top of bedrock. Schedule 80 PVC
casing (8” dia.) was installed in the hole and the annulus between the casing and borehole was
filled with Type V cement. A double plug method was used to cement the annulus; the grout set for a minimum of 72 hrs.
A 6-in diameter steel casing was set in the hole to protect the 8-in PVC during subsequent drilling.
A 5 7/8-in diameter hole was drilled by a dual-wall reverse circulation method to a depth of approximately 50 ft below the oxide-sulfide contact. The exception was in BHP-2, where a 9
7/8-inch hole was drilled through the zone of six-inch diameter core. The 6-inch steel casing
was then removed from the upper portion of the hole.
Schedule 80, slotted PVC casing (4” dia., 0.04” slots) was installed in the entire length of the
open hole. Approximately 10 ft of bentonite, silica sand, and gravel were packed into the bottom of the 12 ¼- inch diameter hole between the 8-in and 4-in PVC casing. The top portion of the 4-
in PVC was then removed so that the 4-in PVC extended 25 to 118 ft up into the lower portion
of the 8-incasing.
A well head was installed and the well was developed by the drilling company.
Ground or hole conditions forced several changes in the general plan especially in BHP-1 where excessive well development in highly fractured bedrock resulted in washout zones of 2-3 feet in
diameter. Only 120 feet of 6-inch steel casing was retrieved in BHP-1; the remaining 280 ft slipped
50 feet down into the RC portion of the hole (between 170-453 ft bgs) and proved impossible to extract. A smaller diameter of screened PVC (1 ½”) was installed in BHP-1 and BHP-3; no gravel
pack was placed in these holes.
3.1.2 Chemical Monitoring Wells
The chemical monitoring wells CH1 and CH2 are located in representative locations along the pilot
test flow path (one-third and two-thirds along the length of the flow path and half way along width of
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flow path. The wells have three manually operated, water quality samplers installed in the screened
sections of the oxide formation at a depth of 420 (top one-third of the injection zone), 610 ft bgs, and 720 ft bgs (Figure 3-1). The well coordinates and construction details are listed in Table 3-1, and the
construction design is shown on Figure 3-3.
CH1 and CH2 have discrete sampling devices located at each of the three well screens per well, but the sampling devises are not physically separated through use of a packer or rubber boot so some
vertical mixing likely occurred. A detail of a sampler is shown on Figure 3-4. The samplers were
custom-made by the BHP Copper Miami maintenance shop with a 1½ inch diameter stainless steel pipe with stainless steel caps welded at each end. Two swage fittings are installed at the top and one
swage check valve at the bottom of the sampler (Figure 3-4). The bottom swage fitting is a check
valve fitted with a ball seat. When the sampler is not pressurized, the fluid in the well forces the
check valve ball to float and the sampler is filled with water from the well.
One of the swage fittings on top of the sampler is connected to high pressure polyethylene tubing
that extends to the surface and is connected to a high pressure cylinder of nitrogen (Figure 3-4). The
other swage fitting is for sampling. The polyethylene tubing extends into the sampler to about one inch from the bottom of the sampler and extends to the surface. Three samplers hang in the well
with 316 stainless steel aircraft cable. The polyethylene tubing was rated at 1,000 pounds per square
inch (psi).
To operate, the sampler is allowed to fill with water, and is then pressurized. The compressed nitrogen enters the sampler and forces water up the poly tubing (that extends into the sampler)
(Figure 3-4). The fluid is forced up the tube to the surface until nitrogen gas exhausts. This process
is done until three sampler volumes were removed and the third was kept as a sample. Nitrogen gas was used initially, but was eventually replaced with cylinders of breathable air (P. Kelm, oral
commun., 2010).
3.1.3 Observation Wells
Six groundwater level monitor wells were drilled by rotary methods with blank casing in the top 40
ft of bedrock and screened in the oxide. The wells were installed surrounding the test area to
monitor the inward hydraulic gradient. All were installed in the oxide zone with the exception of OWB-2, which was drilled within the Upper Basin Fill Unit. The wells sampled when the wells
were first drilled and periodically sampled during the rinsing phase. The samples were taken with a
standard bailer in the blank casing immediately above bedrock, and the borehole was not pumped or purged until remediation activities began. Elevated sulfate was detected in OWB-1 and OWB-4
during the pond water injection phase. The sulfate quickly fell to background levels when injection
wells BHP-6 through BHP-9 were reconfigured to become recovery wells and WW-4 water was
injected in BHP-1. These two observation wells are located in the northeast and southwest portions of the wellfield adjacent to BHP-10 and BHP-5, which had the highest sulfate concentrations
measured during the test.
3.1.4 Cementing Practices
B & C provided the cementing plan in the application for the Aquifer Protection Permit (1996b).
The cementing program includes procedures for drilling and casing new wells (B & C, 1996b,
Section 2.1.3), and for abandoning exploration diamond-drill holes and retired wells (B & C, 1996b, Appendix E). The purpose of the cementing program for newly drilled wells is to support the casing,
to restrict fluid movement between formations in the casing-borehole annulus, and to prevent
excursion of leach fluids from the casing into the formation.
Following the recommendations of B & C and Layne Christensen, the primary cement job on BHP-1
through BHP-5 was performed by pumping cement slurry down the casing and up the borehole
annulus. The drilling contractor used specialized equipment to control the Type V, acid-resistant and
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sulfate-resistant cement. Significant factors contributing to successful cementing include: pipe
centralization, good circulation and mud conditioning (low viscosity and low yield point), high displacement rate, and adequate contact time of the cement with the borehole wall. Barite mud was
used to achieve a high displacement rate and to prevent back flush of the cement slurry.
The borehole cement was allowed to set prior to drilling the screened portion of the well, and the well construction was not approved until the compressive strength samples passed the requirements.
A downhole cement bond log survey was also performed, which gave immediate feedback on the
presence of voids in the cement.
During the cementing of BHP-1 through BHP-5, Layne took four slurry samples for 7-day, 14-day,
21-day, and 28-day compressive strength tests. The cement samples were analyzed by Western
Technologies, Inc. of Phoenix; the cement samples met the specifications (500 psi compressive
strength) required by the Arizona Department of Water Resources (ADWR). The majority of the samples met the 500 psi specification within 21 days.
On the remaining 15 wells (BHP-6 through BHP-13, CH-1, CH-2, OWB-1 through OWB-6), 13 of
the wells passed the cement test (>500 psi) at 7 days. BHP-9 and OWB-2 passed at 14 days.
3.1.5 Mechanical Integrity Tests
In compliance with federal regulations, BHP had to design, install, operate, maintain, and close wells
in a manner that prevents contamination of the surrounding aquifer (B & C, 1996a). A program to test for the mechanical integrity of the wells was an integral part of upholding the EPA Underground
Injection Control (UIC) permit. Cement bond logs, heat logs, or other techniques can be used to test
the integrity of the cement casing but the cement bond log was the preferred downhole log used. Prior to operation, each well was pressure-tested for leaks for 30 minutes. Wells that fail the test are
deemed to be inoperable until the well casing is repaired and the pressure test is successful. The
pressure test can be accompanied by other activities including: (1) an inspection of the casing by a
downhole video camera, (2) a static head test of the solid casing with the bottom shut-in, (3) a density logging of the entire cased interval to verify lack of voids in the annulus between the casing
and the borehole wall, and (4) an acoustic logging of the casing interval above and possibly below
the perforated section while injecting clean water to detect flow behind the casing (B & C, 1996a, section 4.5.2.5).
Based on the UIC permit, BHP was required to submit the results of mechanical integrity tests to
EPA on a quarterly basis. The injection and recovery wells were tested prior to operation and were supposed to be tested every five years following installation. To date, a double-packer system has
been used in the mechanical integrity tests at Florence. A lower packer was installed immediately
above the proposed injection interval; the upper packer was installed near the top of the casing. The
well bore was filled with water and a hydraulic pressure of 60 psi (maximum allowable wellhead pressure) was applied. The test was conducted for a minimum of 30 minutes. The wells passed the
integrity test if there was less than five percent decrease or increase in pressure over a sustained 30-
minute period.
All of the Florence wells that have been tested passed the test at about 60 psi. Using seal lube on the
threads of the casing ensured extra protection against leaking. Without seal lube, the casing threads
were observed to leak as shown by casing tests on the surface. Some of the wells lacked the seal
lube, but still passed the mechanical integrity tests because there was a good bond between the casing and the Type V cement in the borehole annulus. Records on the results of the mechanical
integrity tests were recorded in the project Access database and on hard copy forms filed on site.
3.1.6 Wellhead Design
The wellhead includes equipment that holds the downhole-tubing string in place and provides
pressure sealing. Additionally, wellhead equipment includes the various pressure gauges,
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instruments, valves, fittings, and pipes associated with controlling flow into or out of the well. These
various parts measure the fluid pressure and flow rate, and are used for sampling fluids.
BHP staff developed a general plan for the wellhead design for the injection and pumping wells as
shown on Figure 3-5. The instruments used on injection well BHP 1 included:
One flow meter and controller, 60 gpm,
One pressure transducer, 100 psi,
Conductivity probe and pressure gauge, and
One pump, 7.5 hp, 60 gpm.
The instruments used on the each pump well included:
One flow meter and controller, 15 gpm,
One pressure transducer, 100 psi,
Conductivity probe, and
One pump, 2.5 hp, 20 gpm.
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Figure 3-2 Well construction design – Injection and recovery wells
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Figure 3-3 Well construction design – Chemical monitor wells
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Figure 3-4 Discrete sampler for chemical monitoring wells
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Table 3-1 Summary of well construction details
Well ID Northing (ft)
Easting (ft)
Ground
Elev. (ft amsl)
Meas.
Point Elev. (ft amsl)
Top of
Sulfide Zone (ft bgs)
Total
Depth (ft bgs)
Bottom
Outer Blank
Casing (ft bgs)
Top
Screen1
(ft bgs)
Bottom
Screen (ft bgs)
Pump
Depth (ft bgs)
BHP-1 744923 649371.6 1463.73 1463.51 764 800 403 380 3 740 360
BHP-2 744870.8 649422 1463.61 1463.24 864 894 408 290 2 770 300
BHP-3 744975.8 649419.5 1464.02 1463.24 854 872.5 403 341 3 860 300
BHP-4 744975.9 649320.3 1464.21 1463.74 784 834 403 341 2 742 300
BHP-5 744877.1 649321.9 1463.9 1463.54 770 798 403 375 2 776 300
BHP-6 744923 649420.2 1463.74 1463.7 7507 820 410 385
3 805 300
BHP-7 744974 649371.9 1464.13 1463.1 800 810 410 400 3 760 300
BHP-8 744923.6 649320.8 1463.59 1463.6 780 790 410 400 3 780 300
BHP-9 744874.3 649371.1 1463.86 1463.9 7607 850 410 400
3 840 300
BHP-10 744923 649371.6 1463.73 1463.65 8207 837 400 400
3 820 300
BHP-11 744923 649371.6 1463.73 1464.4 8007 805 400 380
2 800 300
BHP-12 744923 649371.6 1463.73 1464.2 6 770 400 390
2 770 360
BHP-13 744923 649371.6 1463.73 1463.3 7607
840 420 386 2 826
8
OWB-1 744975.9 649470.8 1463.87 1463.7 8207 830 420 395
3 795 240
OWB-2 745026.2 649321.1 1464.27 1464.3 6 225 200 200
2 220 200
OWB-3 744976.4 649270.6 1464.51 1464.5 7507 820 420 396
3 796 240
OWB-4 744873.6 649270.3 1463.72 1463.7 6 755 410 405
3 745 240
OWB-5 744873.9 649470.9 1463.24 1463.2 7607 765 420 405
3 765 240
OWB-6 745134.0 649160.0 146.00 9
6 925 420 380
3 920 240
CH-1 744935.0 649381.9 1463.90 1464.92 4
7607 789 N/A 420
2 789
420,
610, 720
5
CH-2 744934.3 649407.9 1463.72 1464.61 4
6 775 N/A 420
2 775
420,
610, 720
5
Notes: Compiled by SRK 1 = top of screened PVC may be within outer blank casing
2 = 4” screen
3 = 1.5” screen
4 = Casing elevation
5 = Discrete sampling points; no pumps installed
6 = Top of sulfide zone was not encountered before total depth of well was reached
7 = Top of transition zone; sulfide was not encountered before total depth of well was reached
8 = Records do not indicate pump depth
9 = No record of surveyed measuring point
There is no sand pack in BHP-1 or BHP-3 in the screened intervals.
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Photo date 1999
Figure 3-5 Wellhead infrastructure design
3.2 Test Facilities Design
As mentioned previously, the field test included four injection wells that were surrounded by a set of recovery wells to prevent outward migration of process solutions as shown in Figure 3-1. All of the
pump-out flows were captured and conveyed using high density polyethylene (HDPE) pipes to a
series of tanks at the tank farm and ultimately into the 7-acre evaporation pond.
The injectate consisted of well water from site well WW-4 mixed with raffinate obtained from the
BHP San Manuel SX/EW Plant in San Manuel. For limited periods (first day and during 1-week
maintenance period at end of December 1997), the WW-4 water was mixed with sulfuric acid only.
The injectate was filtered first through a set of carbon filters and then through a set of 3-micron bag filters. There was no attempt to extract the copper produced as metal from the process solution
recovered from the wellfield. BHP’s operational experience led them to conclude that solvent
extraction technology was developed sufficiently that no test was required on the processing of the copper solution or production of copper cathode. All of the recovered copper solution was deposited
in the evaporation pond.
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3.2.1 Tank Farm
The tank farm layout was designed by the Winters Group of Tucson. It consisted of:
A new 5,000 gal stainless steel sulfuric acid tank capable of holding 93 percent sulfuric acid,
An insulated 3,000 gal sodium hydroxide tank fitted with heat traces to prevent the normal freezing of the 40 percent caustic at 57o F,
Two parallel activated-charcoal filters to remove any entrained organic from the wellfield injectate,
Three parallel bag filters fitted with 3-micron bags and differential pressure gages, and
A concrete truck off-loading pad for receiving shipments of sulfuric acid, caustic, and raffinate from the BHP San Manual Plant. For safety purposes all of the truck off-loading receiving pipes were
fitted with different sized Cam lock disconnects. The trucks were required to have their own off-
loading air compressors and the appropriate fitting to matchup with the site Cam lock fittings.
The following tanks are all 5,000 gallon capacity and made of HDPE. These tanks included:
Two raffinate tanks,
One pregnant leach solution (PLS) tank,
One water tank, and an
Injectate tank.
An 80-mil HDPE liner was laid under the concrete truck off loading and tank farm areas and graded downward toward the pond and welded to the keyed liners.
Below the tank farm is a ground mat that is also tied into the pond fence. The ground cable was
installed to meet Federal electrical safety standards. A set of Jersey barriers with seep holes was installed parallel to the west pond wall; the area under the tank farm concrete tank and pump stands
was filled gravel to allow drainage to the pond. All tanks are fitted with level indicators.
All of the flows exiting the tanks along with tank elevations were monitored. Flows were measured via MagFlow meters calibrated against tank volume changes. The outputs of the level indicators and
Magflow meters were sent to the distributive control monitoring system.
Acid from the sulfuric acid tank went through the positive-displacement pump and acid was injected into the injectate line via a horizontal in-line mixer. Caustic was metered directly into the line into
the evaporation pond. Both were fitted with feed forward sensors so that flow stopped if there was
no flow in the process lines. Both acid and caustic systems were fitted with redundant check valves
back flow preventers.
3.2.2 Piping and Surface Layout
All of the piping in the plant and wellfield are constructed of welded 3-in diameter HDPE. The piping, valves, meters, well heads, pumps, tanks, truck off-loading areas, and pilot process facility
are constructed on lined HDPE pads to prevent contact with the native soil in compliance with the
1998 Arizona Department of Environmental Quality (ADEQ) Mining Guidance Manual - BADCT
(see Figure 3-5).
There are three HDPE pipelines to the wellfield from the tank farm. They are laid in a bermed
trench lined with 80-mil HDPE to prevent any exposure of the solutions to the native soils.
All of the pumps and fittings in the tank farm area except the water pump and acid pump are constructed of 316 stainless steel; the water and acid pumps are mild steel. All of the pumps are
horizontal centrifugal except for the acid and caustic pumps, which were positive displacement
pumps.
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Evaporation Pond
The double-lined evaporation pond was designed by Fluor Daniel Wright of Vancouver to meet ADEQ BADCT requirements. It was sized based upon the expected inflows from the wellfield and
rainfall, and evaporation rates based on the site pan evaporation rate. A net evaporation rate was calculated and the pond surface area was established at 7.5 acres for the initial pond. This was to be
one of eight similar ponds for the ultimate full-scale production at Florence. The pond site was
moved northward slightly owing to the presence of archaeological sites.
The pond was excavated and cut material place on an unlined pad in the farm field to the northwest of the pond, as shown on Figure 3-6. The area was excavated to a depth of approximately 35 feet
with the sump at its low point at the middle of the north wall of the pond.
The bottom 80-mil HDPE liner was laid on compacted fill to a 95 percent compaction (ASTM 1557). All welds were vacuum soap tested, and selected test pieces were taken and pulled for
tension measurements. The liner was doubled lapped. An 8-in diameter schedule 80 PVC pipe was
placed at the sump and extended to the surface. The bottom of the pipe was perforated to allow
inflow of any potential leakage. A geonet was laid over the entire lower liner and then covered by an 80-mil HDPE upper liner; it was welded in the same manner at the bottom liner.
The liners were keyed into the berm surrounding the pond according to BADCT prescriptive
requirements. The liner was laid into a 2-foot deep trench and up the outer trench wall. The trench was filled with compacted earth to a 95 percent Procter.
The tank farm liner that was laid under the truck off loading and tank farm areas was graded toward
the pond and welded to the keyed liners as noted earlier.
One design-related problem occurred during operation. The 8-in diameter inter-liner leach fluid
collection pipe partially collapsed and pressed downwards in a slight bend owing to the weight of the
water. The leach fluid recovery pump became entrapped in the pressed pipe and could not be
removed until the water in the pond evaporated. It is highly recommended that this pipe be replaced with a stainless steel perforated pipe before initiating the PTF.
Photo date 1999
Figure 3-6 Excavated pond, earth pile to northwest, tank farm, and wellfield to west
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Photo date 1999
Figure 3-7 Evaporation pond, floating dock, and boat for access to pond and sprayers
Photo date 1999
Figure 3-8 Evaporation pond embankment, liner keyed into berm, and 8-foot anchor fence
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Photo date 1999
Figure 3-9 Senniger high-evaporation sprayers floating on 3-in welded HDPE piping. Yellow Jerry cans are for flotation support
Distributive Control System
An Allen Bradley distributed control system was installed in a rental trailer. The trailer (Mobile Mini) was installed on a pad on the south side of the pond fence. The controller was connected to a
computer with a monitor. The monitor displayed the following in real time and displayed the
following recorded information:
Tank levels,
Flows to the wellfield individual wells in the wellfield,
Flows from the wellfield individual wells,
Combined flows to the wellfield,
Combined flows from the wellfield,
Acid injection rates from the acid tank,
Caustic injection rates to the neutralization system,
Tanks level alarms for overflow prevention (high-high),
Transducer outputs from the levels in the wells, and
Conductivity and pH.
Wellfield net inward hydraulic control was maintained automatically by the control system. Whenever the gradient might be lost, the controllers adjusted flow to the individual wells to maintain
the hydraulic gradients.
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3.2.3 Fluid Management and Filtration
The BHP principal hydrologist established the flow criteria to and from the wells. The plant
operators maintained the proper mix of raffinate, water, and pond recirculation solution to the
wellfield. The ratio of raffinate in the injectate, however, changed through time as can be seen in Figure 3-10. Through Day 46 (December 16, 1997), the percentage of raffinate in the injectate was
kept at 8.5% although short-duration operational spikes occurred that ranged from 6.1% to 10.6%.
The raffinate percentage in the injectate was reduced to an average of 5.8% through January 6, 1998
and 4.1% through the end of the test on February 9, 2008. The initial reduction was made as an experiment to assess impact on copper recovery. When the total dissolved solids concentrations
began to build in the pond, some pond water was pumped into the raffinate tanks in lieu of raffinate
and was used as make up; this produced the variable raffinate to injectate ratio seen between January 7, 1998 and February 6, 1998. During this time, the injectate included a mix of pond water,
groundwater from WW-4, and raffinate.
Free acid levels to the wellfield were maintained between 5 and 10 g/L. The caustic addition to the
feed fluid to the evaporation pond was maintained at a minimum pH 4.5.
All injectate was passed through parallel activated charcoal filters to remove and free or entrained
organic from the raffinate received from San Manuel SX Plant. The filters were operated one at a
time via by-pass valves. Whenever pressure began to build the units were switched and backwashed into the pond. The injection of raffinate ceased from December 24-29, 1997 during a period when a
leak in the carbon filter was identified and fixed. During this maintenance period, the injectate
consisted of sulfuric acid and WW-4.
The filtered solution was the passed through a set of two bag filters fitted with 3 micron bags.
Whenever the differential pressure began to build, one filter was switched out and the third switched
into the system to allow changing of the bags. The bags were rinsed with fresh water and disposed
in a landfill. No solution was allowed to be injected until it had passed through both the carbon filter and particulates filters.
Source: Originally prepared by M. Brewer, BHP; modified by SRK, 2010
Figure 3-10 Ratio of San Manuel raffinate to injectate during field tests
0%
2%
4%
6%
8%
10%
12%
10/31/97 11/14/97 11/28/97 12/12/97 12/26/97 1/9/98 1/23/98 2/6/98
Rati
o
Date
Ratio of San Manuel Raffinate to Total Injectate (gal/hr)
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3.2.4 In-ground Environmental Monitoring Methods
Figure 3-2 illustrates the construction of the injection and recovery wells. In-ground environmental
monitoring was based on routine measurements of annular resistivity probes installed on the casing
centralizers. The conductivity monitoring probes were designed to detect any excursion of high-conductivity leachate into the UBFU through the concrete along the casing annulus. The well
centralizers were fitted with conductivity probes from just above the bottom of the grout seal through
20 foot above the clay zone. These were simple two strand wires cut at different lengths and tied to
the centralizers. Resistance was measured at surface with a volt-ohm meter at various voltages. Measurements were taken at regular interval over periods of time ranging from 2 to 10 minutes to
allow for stable readings and bleed off from the meter itself. Electrical resistivity values (ohms/cm2)
were then converted to conductivity values (µS/cm). Baseline measurements were taken prior to the injection of any acidic solution. Reading were taken manually on a weekly basis by the on-site
instrumentation technician and entered into an Excel spreadsheet that calculated the resistance
measurements for the cement and cable.
Figure 3-11 shows the annular resistivity of selected wells on a weekly basis from November 26, 1997 through May 1998 and then quarterly until July of 2001. As can be seen, slight increases in
resistivity were noted in all wells at initiation of the field test but the readings stabilized during the
field test and post-test rinsing phase with the exception of BHP-8. BHP-8 went from 10 Kohms to 29 Kohms. This was due to the materials used, large gauge copper wire (also used for the pump
wires) and steel bands. The end of the copper wire and steel bands were exposed to the concrete
grout. Oxidation occurred during the well use period which caused an increase in resistance at the copper-steel connection point.
Because the injection wells could not be accurately sounded while operating, BHP used calibrated
pressure transducers made by PWI of Tucson. These were calibrated using a two-point method 100
feet apart, and by verifying depth with a depth sounder. The pressure transducers were located just above the pumps or mid-level of the injection fluid levels. They were commercially available
transducers that could monitor solution level within 0.1 feet. These specially designed piezoelectric
transducers used were the first generation of transducers that could be used in a dynamic changing head situation.
Unfortunately, the transducers needed to be constantly recalibrated, and drifts as much as 2 m of
head occurred in a 48-hr period (M. Kline, personal communication, 2010). This was caused by the radical changes introduced in the system by the San Carlos Irrigation and Drainage District (SCIDD)
irrigation well BIA10B, which is adjacent to the 760 ft north-northwest of the field test area. The
operation of the well (~1500 gpm) could induce a change of 20 to 30 feet of head in a 48-hr period,
with no advance warning by SCIDD of when the well would be turned on or off. Most transducers at the time were only designed to operate in a narrow range and couldn't handle such an abrupt
change. Although the PWI transducers BHP used were the best available at the time and performed
better than BHP’s TROXLER data loggers, they were still prototypes, which didn't have the great sensitivity or ability to adjust to the extremes imposed by operation of the nearby irrigation well (M.
Kline, oral commun., 2010).
Environmental Data Processing
The field test cells used a computer-based SCADA (System Control and Data Acquisition) system to gather data from the remote telemetry systems in the well field. The remote units stored data locally
until the information was uploaded to the central computer. Three programs were used to convert the raw data into a usable format: Datatran.exe, Filter.exe, and a batch file named week.bat.
The telemetry system would occasionally receive false data due to static build-up in the
instrumentation lines. To limit extreme biasing of data, the Filter program was modified to remove
false readings. These programs allowed data import to Excel or other spreadsheet applications.
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Figure 3-11 Annular resistivity in Kohms
Annular Resistivity in Kohms
0.0
5.0
10.0
15.0
20.0
25.0
30.0
11/2
5/97
1/24
/98
3/25
/98
5/24
/98
7/23
/98
9/21
/98
11/2
0/98
1/19
/99
3/20
/99
5/19
/99
7/18
/99
9/16
/99
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5/99
1/14
/00
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/00
5/13
/00
7/12
/00
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/00
11/9
/00
1/8/
01
3/9/
01
5/8/
01
7/7/
01
9/5/
01
11/4
/01
Date
Ko
hm
s
BHP6
BHP7
BHP8
BHP9
BHP10
BHP11
BHP12
BHP13
OWB1
OWB4
OWB5
CH1
CH2
OWB3
OWB3 values
show n x5 scale
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3.3 Conclusions and Lessons Learned
In general the installed system performed as designed; however a number of problems were
encountered during the test. These problems and the suggested remedies are shown Table 3-2.
Table 3-2 System problems and resolutions
Problem Resolution
Grundfos downhole pump and motor failures and clogging
The motors were replaced under warranty with more reliable units.
The pumps were modified and the pump check valves were drilled out to allow reversing of the flows through the pumps to clear precipitates and algae. This action resolved the issue.
Conductivity probes gave inconsistent readings. A Wheatstone bridge system was used that allowed dampening to be applied along with averaging. This action resolved the issue.
The well flow control system software developed by the University of Arizona did not work well. Flows bounced and were inconsistent.
The on-site staff recreated the software in C++, which allowed dampening, and signal averaging. This action resolved the issue.
The evaporation pond filled up more rapidly than originally anticipated due to additional hydrology tests, rainfall, operator control, and seasonal effects.
A set of Senniger evaporator sprayers were installed on the pond, but were not sufficiently effective to control pond water elevations. More robust evaporators were needed and evaporation should have started earlier in the test.
The pressure transducers in the wells were hung in the injection wells. The net result is the readings jumped as the fluids dropped into the wells.
The wells were already constructed and no thief tubes could be added to dampen the readings.
Birds landed on the evaporation pond frequently with one duck dying.
Manual hazing via use of employees chasing the ducks by boat, firing shot guns was largely ineffective.
The majority of significant safety incidents and near misses including one fatality were related to commuting accidents.
A fatigue management system was implemented as most employees traveled to and from the Phoenix and Tucson areas.
The well casings were made of schedule 80 PVC. Cementing the wells was completed carefully to avoid damaging the plastic casing.
One well was completed using Smith vinyl ester fiber cast pipe with casing strengths that exceed 1,000 psi. This avoided all of the special equipment need to protect the pipe.
3.4 Recommendations for New Field Test
Many of the technical operations challenges experienced in 1999 would be reduced now by use of
modern state-of-the art equipment and instrumentation. A few recommendations related to the
operation of the PTF are provided below.
Snow makers (at least three) should be installed prior to the start of the next field test to keep
ahead of water levels in the evaporation ponds. These should be installed on a barge in the
center of the pond to prevent overspray from landing on unprotected areas and to reduce the
noise level detected in nearby areas.
The three discrete samplers in the chemical monitoring wells worked well and provided valuable information on the breakthrough times and water chemistry. They were not physically isolated,
however, so some vertical mixing may have occurred; packers or rubber boots should be used to
isolate each discrete sampler. Additional samplers (3to 6 total) may be desirable to provide
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more detail in the evolution of the water chemistry over various elevations. The increased
numbers of samplers, however, should be viewed from a practical eye with respect to the added complexity of the well installation, sample collection procedures, and increased analytical costs.
Listed below are recommendations to consider for injection/recovery well design.
More substantial conductivity probes should be evaluated and installed during construction of the new wells.
The field test wells had 8-inch upper casings with an inner, temporary sleeve that was used to prevent damage to the PVC during drilling of the 5 7/8-in borehole in the ore zone. A droppable
RC drill bit was used so that the RC rods could remain in place while the 1.9-in ID (1.5-in OD)
PVC casing could be installed in the injection zone. A review of current bit sizes, casing diameters, and diameters of the injection pipe materials should be made to evaluate the potential
for downsizing the well and casing diameters while still providing the diameters needed for all
stages of drilling and well installation. This has potential for a large savings in life-of-operations
capital costs if revised dimensions in one or more wells demonstrate that they can be installed and show reliable performance during the PTF activities.
In the UIC permit, PVC, fiberglass-reinforced plastic (FRP) or other corrosive resistant casing is
allowed. FRP if used is to be made from aromatic amine epoxy resin, which provides chemical
resistance for sulfuric acid process solutions. SRK recommends evaluating the cost-benefits of
replacing the PVC casing with Smith vinyl ester pipe or equivalent such as Certa-lokTM PVC. The additional cost is offset by greater strength and resistance to pressure. Certa-lok PVC is
extremely resistant to harsh environments, acids and other chemicals and is commonly used for
Class III injection well construction. Thief tubes should be installed on all wells that allow insertion of pressure transducers to read with wide fluctuation of head in the wells.
Positive displacement cementation allows the entire annular space to be cemented in one fluid process and provides a superior annular seal.
Generally an injection well passes mechanical integrity testing if cementing records, such as the
cement bond log, demonstrate complete filling of the annulus between the casing and the well
bore. Cement pressure testing of the production casing is not only a permit requirement, but is
also the industry standard secondary test; performing these tests provides continued value going forward as proof that the well was properly constructed.
Drilling out of the production interval using lower cost mud rotary methods as opposed to
reverse circulation may be economically beneficial if the mud cake can be thoroughly removed
during well development. The downside is that the sample collected will not be usable for
assaying purposes. The rotary drilling only option would be appropriate in the observations wells.
Current industry well completion practice is generally through the installation of a production screen and a separate telescoped liner into the production zone. The liner is sealed within the
production casing with a series of two rubber k-packers or m-packers (triple seal). For an acid-
injection application, these rubber packers would be constructed of silicon rubber to prevent chemical degradation of the rubber. By utilizing a rubber-sealed liner, the size can be increased
to bring the screen wall closer to the formation (i.e. 6-in production casing, 5 5/8-in drill out, 3-
in or 4-in screen.
A 3-in or 4-in screen dimension allows for more rigorous well development but may need to be
replaced by 1.5-in ID screen in boreholes with poor rock stability. Well development is faster and more successful the closer the source of energy is to the producing formation.
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4 Hydrologic Site Characterization Extensive summaries and white-papers have been prepared by BHP and predecessor companies on
the hydrological characterization and numerical flow models for the Florence deposit (Conoco, 1976,
Magma, 1994; and BHP, 1997c, d; BHP, 1999). Project-scale aquifer tests, baseline water quality sampling and modeling were performed to support environmental permit activities and to assess the
representative properties of various aquifers (B&C, a, b). Aquifer tests and test-scale modeling were
performed in the field test area before and after the injection of raffinate. The sections below provide an overview of the local hydrology and the project-scale and field-test scale test work.
4.1 Hydrogeological Characterization of the Deposit
The major surface water feature in the area is the Gila River, located about 0.5 miles south of the
project area. Because of upstream diversions (Florence-Casa Grande Canal and North Side Canal),
the Gila River is generally dry with the exception of flow caused by brief, intense seasonal rainfall. Two watershed drainages (East Drainage and West Drainage) transect the mine and administration
areas but discharge only ephemeral flow to the Gila River. Consequently, infiltration of river water
into the upper basin-fill sediments is limited to periods of ephemeral flow.
The regional groundwater gradient is from the recharge zone along the Gila River flowing north-
northwest to the Salt River Basin. Historically, regional groundwater withdrawals have been
primarily been related to agricultural uses and utilize the upper and lower basin-fill aquifer.
Locally, the aquifers correlate well with the lithologic units identified in the project area; the
hydraulic properties, pump tests, and water quality data confirm that there is little vertical
communication between the aquifers. The approximately 370 ft of unconsolidated conglomerate and
alluvial material overlying the deposit was divided into five units (BHP, 1997a): (1) Quaternary Alluvium (Qal), (2) Upper Loose Conglomerate (ULcgl), (3) Upper Cemented Conglomerate
(UCcgl), (4) Clay, and (5) Lower Cemented Conglomerate (LCcgl). Flat-lying basalt flows and
dikes were encountered by drilling in the poorly indurated conglomeratic unit. The ULcgl is the principal source of groundwater in the area, primarily for irrigation purposes; the aquifer for this unit
is called the Upper Basin-Fill Unit (UBFU). The Clay layer is approximately 20 to 40 ft thick and is
50 to 70 ft above the top of bedrock over most of the deposit area; the aquifer in this unit is called the Middle Fine-Grained Unit (MFGU). The LCcgl varies in thickness from 50 to 800 ft and consists of
weakly to moderately cemented conglomerate; the aquifer in this unit is the Lower Basin-Fill Unit
(LBFU). Table 4-1 correlates the aquifer units associated with the lithologic units found in the
project and field test area.
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Table 4-1 Correlation of geologic and hydrogeologic units in the basin fill formations
Lithologic Map Unit
Lithology Aquifer Unit
Aquifer Description
Comments
Qal Quaternary alluvium Qal Alluvium Recent, coarse-grained, highly permeable, unconsolidated sediments
ULcgl Upper Loose Conglomerate
UBFU Upper Basin-Fill Unit
Laterally uniform, coarse-grained, permeable, unconsolidated, sediment, and matrix-supported conglomerate.
Wells have a "GU" designation for Gila (Conglomerate)Upper
UCcgl Upper Cemented Conglomerate
UBFU
Clay Clay MFGU Middle Fine-Grained Unit
Laterally extensive, fine-grained, calcareous silt/clay unit with low permeability
LCcgl Lower Cemented Conglomerate
LBFU Lower Basin-Fill Unit
Laterally extensive, coarse- to fine-grained, unconsolidated conglomerate with increasing induration and decreasing permeability with depth.
Wells have a "GL" designation for Gila Lower
Source: Compiled by SRK, 2010
4.1.1 Pump Tests
A series of 49 pump tests in 17 locations were conducted around the site as part of the APP application process. This included 17 major pumping wells and 46 monitoring wells, screened
within different aquifers. Eight wells were completed within the UBFU, 17 within the LBFU, and
38 wells within the oxide aquifer. The pump test results are summarized in Table 4-2. The significantly lower hydraulic conductivity in the MFGU is a favorable feature for ISR operation to
limit the potential vertical migration of process solutions. The low conductivity of the sulfide zone
eliminates the sulfide zone from consideration for an ISR operation.
Table 4-2 Hydraulic parameters of hydrogeological units
Hydrogeological Unit Thickness (ft) Average Hydraulic Conductivity (ft/day)
Upper Basin-fill Unit (UBFU) 200-500 60
Middle Fine-Grained Unit (MFGU)
20-40 0.00014
Lower Basin-fill Unit (LBFU) 50-800 5
Oxide Zone About 440 0.5 (from 0.1 to 1)
Sulfide Bedrock - 0.003
Source: Brown and Caldwell, 1996a
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4.1.2 Measurement of Anisotropy
Pump tests to assess the anisotropy in the oxide zone were conducted in several locations including
the P12 and P19 well clusters located in the northwest part of the project area (see Figure 4-1). The
measured anisotropy ratio at P13 is about 3 and the major principal axis direction is N61°E (Figure 4-2). The anisotropy ratio at P19 is about 1.7 and the major principal axis direction is N78°E (Figure
4-3). The horizontal anisotropy can have a significant effect on effective sweep and copper
recovery. In theory, a large sweep area is obtained when the injection and recovery wells are
installed in the direction of the minor principal direction. When the injection and recovery wells are in the direction of the major principal direction, the solution sweeps a narrow band of rock. BHP’s
evaluation of various well configurations showed that the 5-spot pattern, crossing both minor and
major principal axes, would provide sufficient sweep and was the most cost-effective pattern for the layout of the wellfield.
4.1.3 Well Capacity
The well capacity is the pumping rate per unit thickness of the oxide zone at the maximum allowable drawdown. The maximum allowable drawdown is the difference between the ambient groundwater
level and the top of the pump. For the calculation of well capacity, the assumptions were that the
allowable drawdown was 200 ft., the well has 57 percent efficiency (based on the pumping test results), and the mean hydraulic conductivity of the oxide zone of 0.5 ft/day. A mean pumping rate
of 0.25 gpm per ft was obtained, which did not take into account nonlinear head loss, and the
mechanical and biological clogging of the wells and formation. To be conservative a pumping
recovery rate of 0.1 gpm per foot was chosen (BHP, 1997c). For a 6-in well and a 4-in pump, the maximum flow rate was calculated to be less than 200 gpm.
4.1.4 Hydrophysical Logging
BHP retained Colog, Inc. of Golden, Colorado to conduct a series hydrophysical logging tests in sets
of pumping and observation wells situated across the deposit. One of the tested well pairs, P5, is
located E-SE of BHP-1 in oxide bedrock and is therefore expected to be reasonably representative of
the hydraulic conditions found in the field test area.
The hydrophysical tests were designed characterize the vertical hydraulic heterogeneities and their
correlation with geologic structures. The tests results were used to calculate the flow efficiencies in
the oxide zone. The vertical flow profiles showed that the inflow is not uniform. The percentage of no-flow zone along the wellbore represents the fraction of rock that will not be in contact by lixiviant
directly. The percentage of permeable zones as a function of threshold length is presented on Figure
4-4. The threshold length is defined as the minimum length of impermeable zones in the borehole. That is, any no-flow zone that is less than the threshold length is considered to be a permeable zone.
The rational for defining threshold length is that if a no-flow zone is smaller than the threshold
length, the rock can still be contacted via fluid diffusion and flowing through micro-fractures (Figure
4-4). The average percentage of permeable zone increases from 65 percent at a 5-ft threshold to 85 percent at a 20-ft threshold.
In the oxide bedrock in the P5 well located 265 ft E-NE of BHP-1, the average percentage of
permeable zones measured at both 40 and 70 gpm production rates was greater than 80 percent at a 5-ft threshold. The hydrophysical logs at P5 indicate there was nearly continuous inflow throughout
the wellbore. This favorable condition would be expected to be present at the nearby field test area.
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Source: BHP, 1997c
Figure 4-1 Aquifer test locations in the deposit area
The major principal direction in the vicinity of the P13 well cluster is N61°E. Source: BHP, 1997c
Figure 4-2 Horizontal anisotropic test at the P13 well cluster
P13.1 P13.2
O13.1
K1=0.86 ft/d
K2=0.29 ft/d
29 degree
-0.4
-0.3
-0.2
-0.1
0
0.1
0.2
0.3
0.4
-0.4 -0.3 -0.2 -0.1 0 0.1 0.2 0.3 0.4
North
K1K2
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The major principal direction in the vicinity of the P19 well cluster is N78°E. Source: BHP, 1997c.
Figure 4-3 Horizontal anisotropic test at the P19 well cluster
Source: BHP, 1997c
Figure 4-4 Percentage of permeable intervals as a function of threshold length
The hydraulic connection between wells was estimated by evaluating flow distributions in wells
during stable ambient conditions and during stressed conditions in cross-hole tests. Tests were
conducted in four observation/pumping well pairs. BHP hydrologists concluded that the cross-hole
test results indicated that selective pathways may exist through discrete fractures and occasional changes of well pattern and flow direction may be necessary during operations in order to achieve
high recovery.
4.1.5 Regional Flow and Transport Model
B & C (1996) performed several numerical simulations as part of the APP and Underground
Injection Control Permit (UIC) applications. The numerical models included:
-0.6
-0.4
-0.2
0
0.2
0.4
0.6
-0.6 -0.4 -0.2 0 0.2 0.4 0.6
K1=0.54 ft/d
K2=0.32 ft/d
12 degree
P19.1 P19.2
O19.1
K1
K2
0
20
40
60
80
100
120
0 5 10 15 20 25
perc
en
tag
e o
f p
erm
eab
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nte
rvals
Threshold, ft
PW1-1
PW2-1
PW2-2
PW3-1
PW7-1
P15-O
P13-2
P12-O
P8.1-O
P5-O
P19-1
P28.2
Average
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A regional groundwater model, MODFLOW code,
Transport flow models, PATH3D, a particle tracking code, and MT3D, a contaminate transport
code.
The regional groundwater flow was simulated under expected in-situ operational conditions, including mine closure and post-closure. The grid covered a 10-square mile area, with eight
horizontal layers of varying dimensions. The vertical coverage included the UBFU, MFGU, LBFU,
the oxide zone, and the sulfide zone. The Party Line fault and the Sidewinder fault were assumed to have an order of magnitude higher hydraulic conductivity than was indicated by actual values
measured in the field, at the request of ADEQ and EPA.
A simulation of four years of operation was performed by B & C. Regional groundwater simulation was performed at Year One. The following two years were simulated with regional and mining
pumping (the base case). The fourth year simulated hydrologic variations, where either increased
recharge or withdrawal was investigated.
Simulation of mining under natural conditions included: ISR well operations and important regional stresses and conditions such as irrigation and municipal groundwater pumpage, and the contribution
of the Gila River. Particle tracking simulating the active leaching and hydraulic control showed that
all of the mining solution was contained within the hydraulic zone.
4.2 Hydrogeological Characterization of Field Test
Prior to the raffinate injection phase, hydrogeological characterization was performed with varying
numbers of wells in the field test location. These characterization tests included: differential pump
tests and a groundwater injection tracer test. BHP prepared a numerical flow and transport model
(MODFLOW/MT3D) to estimate the in-situ porosity and dispersivity, and the lateral and vertical excursion of solution. A sweep efficiency simulation was also performed. The tests and findings are
briefly described below and in greater detail in BHP reports and memoranda (1997c, d).
4.2.1 Field Measurements and Data Management
Operators were trained to measure water levels, use the pH and conductivity meters, collect and ship
water quality samples for analysis, download data transducers, and record the results of site
inspections and maintenance repairs. The field measurement entries were generally done by hand into log books with numbered pages that were kept at the control room trailer and on individual field
sheets – much of which were then entered into the project database.
Field measurements were performed using pH and electrical conductivity meters. The YSI meter used until November 17, 1998 was found to be unreliable for pH measurements; the YSI meter did
provide adequate reliability and reproducibility for electrical conductivity readings. The YSI pH
meter was replaced with a Corning meter that was used thereafter with good reliability. Training on both meters and measurement methods was reinforced at regular intervals especially when quality
control issues were noted between different technicians.
BHP used a Microsoft Access database and Excel spreadsheets to record much of the project data
that were collected during the field test. The database is still available for review and inspection. The data collected included well construction and abandonment information, the results of
mechanical integrity tests and field measurements (water levels, pH, EC), pump installation and
service records, laboratory analyses for a variety of constituents, flow rates, and other information. Staff members devised data entry forms for daily data entry activities, standardized reports, queries,
and water quality graphs that updated themselves as new analyses were added.
Water quality analyses including duplicates were performed by three laboratories. Hard copy lab
results were provided – no PDF copies were digitally provided by the laboratories. The water quality analyses were recorded in the Access database by sampling point, date, and laboratory with
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all constituents arranged horizontally across the row. This method did not allow detailed
information to be recorded about each constituent, such as the method detection limit and laboratory qualifiers. Electronic data deliverables were not readily available at that time from all of the
laboratories used. Although queries and reports were developed, the database structure is not ideally
formulated to access unique data records.
Transducers were downloaded by the staff hydrologists and manipulated to track the performance of
the wellfield. The processed data was stored and shared on the hydrologist’s computers.
4.2.2 Pre-Leach Aquifer Pump Tests
BHP staff conducted four pumping test at the 5-spot wells BHP-1, BHP-2, BHP-4, and BHP-5. The
wells are screened approximately 400 ft in the oxide bedrock (Table 3-1). When one well was
pumped, the remaining four wells were used as observation wells. Each test lasted from one day to three days; the water levels were allowed to recover between the test intervals. The observation
wells showed drawdown responses that resemble the Theis curve for equivalent porous media. The
drawdown in all the wells shows a linear relationship between the period of 10 minutes and 1,000
minutes. Then the curves become flatter due to inflow (leaky) from the upper basin-fill aquifer. BHP concluded that based on the four pump tests there is heterogeneity and/or anisotropy within the
oxide zone in the location of the field test location.
The hydraulic conductivity and storativity values generated from these aquifer tests were calculated using AQTESOLV (Duffield, 1996) (software for the analysis of pumping tests and slug tests) are
summarized in Table 4-3. The Theis solution was used, which assumes that the rock is
homogeneous and isotropic. The mean hydraulic conductivity was about 0.6 ft/day and storativity was 0.0007. When the pumping well and observation well were switched, the hydraulic
conductivities obtained were very similar, which was interpreted to be an indication that the data
were very reliable (BHP, 1997d).
Table 4-3 Hydraulic conductivity and storativity from the oxide aquifer tests
Aquifer Test Observation Well K (ft/d) Storativity
BHP-1 BHP-2 0.6 0.001200
BHP-1 BHP-3 0.6 0.00042
BHP-1 BHP-4 0.4 0.00033
BHP-1 BHP-5 0.9 0.00069
BHP-2 BHP-1 0.6 0.00120
BHP-2 BHP-3 0.8 0.00140
BHP-2 BHP-4 0.5 0.00063
BHP-2 BHP-5 0.7 0.00024
BHP-4 BHP-1 0.3 0.00038
BHP-4 BHP-2 0.5 0.00059
BHP-4 BHP-3 0.5 0.00037
BHP-4 BHP-5 0.5 0.00090
BHP-5 BHP-1 0.9 0.00075
BHP-5 BHP-2 0.8 0.00020
BHP-5 BHP-3 1.0 0.00074
BHP-5 BHP-4 0.5 0.00096
Average 0.6 0.0007
Source: BHP, 1997d
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4.2.3 Groundwater Injection Tracer Test
The groundwater injection test was designed and performed to estimate the effective porosity of the
oxide zone as well as the solution dispersion, travel times, and the flow paths that the injected
solution takes. Prior to obtaining the APP the introduction of salt, dyes, and artificial tracers into the oxide zone was not allowed. In lieu of this, an alternate solution of using the distinct chemical
composition of the upper or lower basin aquifer as a tracer was chosen.
Upper basin-fill water from well M10-GU was continuously injected into the central well, BHP-1, at
an average rate of 53 gpm for almost 2 months while wells BHP-2 through BHP-5 were extracting about 13 gpm. Sulfate was used as a tracer to detect the breakthrough curve and assess the reason
for differences in the sulfate mass extracted from each well. The electrical conductivity (EC) of
M10-GU water (1,900 µS/cm) is about twice that of the oxide groundwater (850 µS/cm). Sulfate concentration in the UBFU is about four times higher than that of the oxide water (260 mg/L vs. 60
mg/L).
The breakthrough curves for electrical conductivity and sulfate at extraction wells can be seen in
Figure 4-5 and Figure 4-6. During the first few days, the EC of BHP-3 was at a high level indicating effects of residual drill mud (Figure 4-5). The EC of BHP-3 started to decrease as the well was
pumped and purged of the remaining drilling mud. As the UBFU water reached BHP 3, the EC
curve stopped decreasing. It flattened and started rising as more M10-GU water swept through the oxide water around the BHP-3 area. This behavior was not observed in the sulfate breakthrough
curve of this well because the drilling mud was not high in sulfate content (Figure 4-6).
Almost all extraction wells showed increases in concentration after four days with the exception of BHP-2, whose breakthrough occurred after 18 days. BHP-4 had the greatest sulfate concentration
response of all four pumping wells; its sulfate concentration had increased by three fold by the end
of the test. The sulfate concentration at BHP-3 and BHP-5 had increased by 2.3 fold, while at BHP-
2 it slowly increased by 1.3-fold. BHP-2 was completed in a sliver of quartz monzonite sandwiched by parallel Tgdp dikes. It is apparently isolated from BHP-1 and the other BHP wells by two faults
identified in televiewer logs, as shown on the geologic section on Figure 4-7. These faults, if they
contain significant clay gouge, might cause the low hydraulic conductivity zone around BHP-2.
Source: BHP, 1997d
Figure 4-5 Electrical conductivity breakthrough curves during groundwater injection test
Electrical Conductivity during Water Injection Test
700
900
1100
1300
1500
3/10/97 3/20/97 3/30/97 4/9/97 4/19/97 4/29/97
Time
EC
(m
icro
mh
os/c
m)
BHP2
BHP3
BHP4
BHP5
BIA 10 on
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Figure 4-6 Sulfate breakthrough curves during the groundwater injection test
Figure 4-7 Diagonal NW-SE section (looking southwest) showing screened intervals in undifferentiated bedrock and the faults between BHP-1 and BHP-2
Sulfate Concentration during Water Injection Test
40
60
80
100
120
140
160
180
3/10/97 3/20/97 3/30/97 4/9/97 4/19/97 4/29/97
Time
Su
lfate
(m
g/L
)
BHP2
BHP3
BHP4
BHP5
BIA 10
on
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4.2.4 Numerical Modeling
BHP used numerical modeling as a preliminary assessment of transport and movement of solution in
the oxide aquifer at the field test location. The flow model was constructed using MODFLOW
(McDonald and Harbaugh, 1988). Subsequently, the computed heads and cell-to-cell fluxes were utilized in MT3D (Zheng, 1990) for the simulation of transport.
The computer model incorporated available data on hydrologic and geologic conditions, aquifer
properties, and water quality to simulate groundwater flow and advective-dispersive transport of a
conservative species within the aquifer. The porosity and longitudinal dispersivity in the oxide zone were calibrated against sulfate breakthrough data in four observation wells approximately 70 feet
from the sulfate source.
The hydraulic configuration that best matched the observed drawdown patterns in the four aquifer tests is shown in Figure 4-8. This figure shows the detailed two-dimensional K zones within the 5-
spot, the K values for the rest of the oxide area had values of 0.6 ft/d. It was necessary to use a low-
K (0.05 ft/d) trend cutting southwest to northeast between BHP-1 and BHP-2 and an almost no-flow
zone (K = 0.01 ft/d) northwest of BHP-4 to reproduce all four oxide aquifer tests.
Source: BHP, 1997d (Red dots indicate the 5-spot wells). Colors indicate K (ft/d) zones: brown = 0.01, orange = 0.05, yellow = 0.1, green
= 0.3, blue = 0.5 or 0.85, purple = 0.6
Figure 4-8 Hydraulic conductivity zones within the oxide bedrock in the 5-spot
4.2.5 Estimation of Porosity and Dispersivity
Effective porosity is the ratio of pore volume allowing movement of fluid to total volume of the
rock, be it porous or fractured. Hydrodynamic dispersion accounts for velocity variations that cause spreading of contaminants over greater and smaller distances than would be calculated by the
average seepage velocity of groundwater alone. This parameter lumps variations in velocities due to
“small” scale heterogeneities which are unknown. By using the numerical model of groundwater
flow coupled with the solute transport model, BHP hydrologists attempted to estimate porosity and dispersivity in the field test by adjusting them during calibration. These parameters were adjusted
until the distribution of the solute concentration approximates measured data. The solute transport
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model, MT3D, was calibrated to the 5-spot water injection data. Using an effective porosity of 10
percent in the oxide aquifer, the numerical model reproduced a fairly good match with measured sulfate concentrations during the first three weeks of the 5-spot tracer test (Chong-Diaz, 1997).
The 10 percent porosity estimate was higher than the previous estimate of 2 percent (B & C, 1996b,
p. 2-12). If this higher porosity value is generally true, it substantially reduces the risk of pore clogging and decrease of fluid flow due to mineral precipitation during the in-situ leaching process.
Further, the lixiviant may be contacting more exposed ore area. However, a higher volume of
lixiviant than previously calculated will be needed to fill the oxide aquifer before copper starts to be extracted.
4.2.6 Evaluation of Hydraulic Control
For environmental and operational purposes, the injected solution must be contained horizontally and vertically) and recovered. The horizontal control prevents lateral excursion of injected solution
to the regional groundwater outside the mining block. The vertical control prevents the vertical
excursion to the aquifer in the LBFU. In the wellfield design, horizontal hydraulic control was
maintained by inducing and sustaining hydraulic gradients inward by pumping from perimeter wells BHP-10, BHP-11, BHP-12, and BHP-13. The vertical hydraulic control is achieved by the
combination of excess extraction and completing the wells 40 ft below the LBFU, leaving a buffer
zone below the LBFU contact with the top of oxide zone.
B & C simulated a specific mine block with flow and particle tracking using MODFLOW and
PATH3D as part of the APP demonstrations. The wells were in a 5-spot pattern, and all the
perimeter wells were recovery wells. The injection and recovery rates for all interior wells were 0.1 gpm per foot of well screen. Based on mass balance of injection and withdrawal, the recovery rates
of exterior wells were calculated. To establish hydraulic control of the mine block, the exterior wells
were pumped at elevated rates. In the simulation, exterior recovery wells were pumped at 25 percent
over the calculated base rates needed to achieve total injection equal to the total withdrawals.
Particle tracking was used to demonstrate the hydraulic control. Fifteen particles were introduced to
the injection solution at the injection wells and then traveled with the solution. Hydraulic control
was successful if all the particles were recovered in the recovery wells. Otherwise, the excess pumping at exterior wells would need to be increased to achieve the hydraulic control. The results of
the simulations by B & C (1996c) showed that hydraulic control could be achieved when perimeter
wells are pumped at 25 percent over the base rates.
An interior five-spot within the wellfield was used to demonstrate the vertical control. A simulation
was performed that injected solutions 40 ft below the contact of oxide zone and overburden.
Artificial particles were introduced to the solution to track the solution movement. A small wellfield
consisting of 13 wells was used to demonstrate the vertical control near the wellfield boundary (B & C, 1996c). The results showed particle tracking of solution movement from an injection well to a
recovery well. No solution was moved into the LBFU under simulated wellfield conditions (B & C
(1996c).
Following the groundwater injection test at the 5-spot, BHP performed a numerical simulation of
horizontal and vertical spreading that might occur after 10 and 365 days of raffinate injection into the
oxide zone using the field test configuration (BHP, 1999). Their simulation indicated a small portion
of the injectate would migrate horizontally to the observation wells located 50 ft beyond the outer recovery wells. In addition, the simulation forecast that the injectate would move 20 to 40 ft up into
the LBFU at the end of one year. The simulation assumed no change in hydraulic conductivity
during the one-year time frame. Laboratory tests on LBFU drill core indicated that the permeability of this material could be reduced by 50 percent in reaction with raffinate solutions owing to mineral
precipitation.
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Profile looking north through field test with 20-ft simulation layers shown in red and black symbols. Recovery well BHP-12 (left), BHP-1
(center), and BHP-10 (right) are shown in black. Injection wells BHP-8 (left) and BHP-6 (right) are shown in red. Simulated sulfate
contours at various concentrations are shown flaring up a few feet above the top of bedrock into the LBFU. BHP, 1999.
Figure 4-9 Simulated vertical concentration profile between injection wells BHP-6 and BHP-8
4.2.7 Sweep Efficiency Estimation
Sweeping efficiency can be defined as the ratio of volume of medium contacted by injected fluid
(e.g., raffinate) to total volume of porous/fractured medium. The solution movement within a well could be different from a neighboring well. The area contacted by solution as a function of time is
called sweeping. Using the data provided by the hydrophysical tests, BHP hydrologists calculated
the estimated sweep efficiency.
Curves of concentration versus time or pore volumes from each discretized oxide layer were plotted.
A table with relationship between pore volume and percent of area contacted by the injected solution
was created. Using hydrophysical data and the table of pore volume and percent of contacted area;
the sweep efficiency for 11 wells were derived. The average sweep efficiency for these 11 representative wells at various locations around the deposit reached 75 percent within three pore
volumes in the path between the injection and extraction wells. A sweep efficiency of 80 percent
was ultimately selected as reasonable estimate for the average operations time period of 5 years.
4.2.8 Well Clogging Considerations
Injection wells typically develop resistance to flow over time owing to well clogging processes
(Pyne, 1990). At the San Manuel ISR operation, for example, gradual well clogging developed in the form of reduced injection capacity and development of no-flow zones through portions of the
screened intervals in the injection wells (as shown by spinner logs). The different clogging
mechanisms include:
Drilling mud residues and mud cake on the borehole wall,
Chemical precipitation in bore holes,
Suspended solids in the injectate solution,
0.050.100.200.300.400.50
0.700.80
0.95
UBFU
OXIDE
LBFU
MFGU
MODFLOW BC Symbols
Well
Point Source/Sink
MT3D BC Symbols
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Microorganisms (particularly fungi), and
Entrapped air bubbles or air entrainment owing to cascading leach solution in the injection wells.
All of these clogging mechanisms result in a reduced permeability (“skin” effect) around the wells.
San Manuel raffinate was used during the Florence field test and was filtered on site as described in
Section 3.2. A combination of dual media filters and activated carbon filters were used for the
raffinate to filter out both solids and microorganisms. Three-micron filters were used for the added
sulfuric acid and make-up water. In order to minimize potential air entrainment, the injection pipes were extended below the water level. The use of acid-resistant grout to cement the well casings was
intended to eliminate one source of gypsum precipitation. Drilling and well installation techniques,
as well as solution handling, were tailored to reduce well clogging and to minimize damage to the bedrock. Clogging did occur, however, primarily as a growth of an amorphous aluminum silicate
and algae seen in selected wells during the injection of evaporation pond water during post-test
rinsing.
4.2.9 Well Bromide Tracer Test Post-Leaching
Following the 101 days of raffinate injection (10/31/1997 to 2/9/1998) of the field test area, the
reclamation phase began. During reclamation, a tracer test using bromide was conducted. Groundwater from well WW-4 (3,000 feet away) and sodium bromide solution were mixed together
with an inline mixer. The mixed solution, with bromide concentration of 54 ppm, was injected into
BHP-1 at 55 gallon per minute for 45 hours. The injected solution was recovered from BHP 2
through BHP-9. The average total pumping rate was 93 gpm. After this time, only groundwater was injected into BHP-1.
The relative concentrations vs. time curves are presented in Figure 4-10. Figure 4-11 shows a
diagrammatic representation of how much solution reached each pumping well. About 56 percent of the injected bromide had been recovered in a 30-day period; the average pumping rate is also shown.
Of note was the fact that the percentage of bromide solution recovered at the pumping wells was not
proportional to the pumping rate or distance from the injection well. For example, BHP-7 pumped at only 7 gpm and recovered 12 percent bromide; BHP-6 being at an equal distance of 50 ft from the
injection well, pumped at a higher rate of 11 gpm but received only 9 percent bromide. BHP-8 and
BHP-9 are of equal distance from the injection well and had a similar pumping rate of 12 gpm, but
they had different results. Fifteen percent of bromide reached BHP-8 and only 6 percent bromide reached BHP-9. BHP-2 and BHP-3 pumped at 7 gpm, but BHP-2 did not recover any bromide and
BHP-3 recovered only 2 percent. BHP hydrologists interpreted this to mean that differences in
heterogeneity and communication existed in the field test site.
The pre-leach groundwater (sulfate) injection tests also indicated the isolation of BHP-2 from BHP-1
and the other BHP wells. The heterogeneity noted in the tracer test response may be influenced by
local geologic conditions. BHP-2 is sitting within a sliver of quartz monzonite that is sandwiched between two E-W striking porphyry dikes and is isolated from BHP-1 and the other BHP wells by
two faults (Figure 4-7).
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Figure 4-10 Relative Br concentration vs. time curves (BHP, 1999)
Br Field Test
Relative Concentration vs Time
Injected 50 ppm for 2 days into BHP1
-0.20
0.00
0.20
0.40
0.60
0.80
1.00
05/13/98 05/18/98 05/23/98 05/28/98 06/02/98 06/07/98 06/12/98
Day
Rel. C
on
c. (p
pm
)BHP2
BHP3
BHP4
BHP5
BHP6
BHP7
BHP8
BHP9
BHP10
CH1
CH2
Br Field Test
Relative Concentration vs Time
Injected 50 ppm for 2 days into BHP1
-0.05
0.00
0.05
0.10
0.15
0.20
0.25
0.30
05/13/98 05/18/98 05/23/98 05/28/98 06/02/98 06/07/98 06/12/98
Day
Rel. C
on
c. (p
pm
)
BHP2
BHP3
BHP4
BHP5
BHP6
BHP7
BHP8
BHP9
BHP10
CH1
CH2
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Source: BHP, 1999
Figure 4-11 Diagram representation of Br percentage reaching pumping wells
4.2.10 Summary of Injection and Tracer Tests
The results of the pre-leach groundwater (sulfate) injection test, the raffinate injection phase, and the post-leach bromide tracer test are summarized and compared in this section. The three injection tests
were performed using different well configurations, groundwater compositions, and pumping rates.
Although the physical area tested and the wells involved are slightly different, a qualitative comparison can be made to summarize the local response seen in the wellfield during each test. The
duration of the tests and the tracked constituents are summarized in Table 4-4. The question to be
answered is whether the responses seen in any particular injection test can provide valuable ground-
truth information that would allow a qualitative or quantitative forecast on the potential behavior seen during raffinate injection.
North
6 % Br
50 ppm Br injected into BHP1 at 54gpm. A Total of 27 Kg Br after 45hours. RECOVERED 57% Br in 1 monthperiod.
BHP9
BHP6
BHP7
BHP8
BHP4
BHP2BHP5
BHP3
BHP10
(13 gpm) (12 gpm) (7 gpm)
(12 gpm) (7 gpm) (7 gpm)
(12 gpm) (11 gpm) (6 gpm)
BHP11
BHP12
BHP13
owb1
owb3
owb4owb5
12 % Br
15 % Br
10 % Br 2 % Br
0 % Br
9 % Br
0 % Br
3 % Br
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Table 4-4 Duration of injection tests
Groundwater Injection Test
(sulfate)
Raffinate Injection
(sulfate)
Groundwater Injection Test
(bromide)
Begin inject 3/12/97 10/31/97 5/13/98
End inject 5/8/97 2/8/98 45 hours
Begin inject water NA 2/19/98 5/15/198
End inject water NA 5/12/98 7/17/98
Note: The pre-leach groundwater-injection test used M10-GU well water. WW-4 well water was used during the raffinate-injection period
and during the bromide tracer test.
As described previously in Section 4.2.3, M10-GU groundwater that was pumped from the UBFU
and contained an average of 260 mg/L sulfate was injected into BHP-1 (60 mg/L sulfate). BHP-2,
BHP-3, BHP-4, and BHP-5 were pumped during the injection test that lasted 77 days from 3/12/1997 to 5/27/1997. A contour map based on the relative percentage of the mass of sulfate
recovered in each of the corner wells from 3/12 to 5/8/97 is shown on Figure 4-12. As shown, sub-
equal amounts of sulfate (~25%) were recovered from BHP-3 and BHP-5 in a N45E trend; the
greatest percentage (31%) was recovered in BHP-4 in the northwest corner; BHP-2 recovered the least percentage (18%).
During the raffinate-injection phase, injectate containing 10,000 to 6,000 mg/L sulfate was injected
in BHP-6, BHP-7, BHP-8, and BHP-9 with inner recovery wells BHP-1 through BHP-5 and outer recovery wells BHP-10 through BHP-13. Figure 4-13 presents a contour map of the percentage of
sulfate mass recovered from each well through May 12, 1998. The majority of the sulfate mass
extracted during this period was recovered from BHP-1 (35%), which was pumped at a rate of approximately 40 gpm. BHP-5 extracted 19% of the sulfate extracted and was pumped at a rate of
approximately 19.3 gpm. The outer perimeter wells recovered 5 to 8% of the mass extracted with
pumping rates ranging from 10.4 to 13gpm. Once again the major principal axis of sulfate extraction
is along a NE-strike.
The post-leach bromide tracer test is described in Section 4.2.9. Bromide was injected into BHP-1 at
a concentration of 54 mg/L bromide for 45 hours. Recovery wells BHP-2 through BHP-9 were
pumped at a total rate of 93 gpm. Following the 45-hr bromide injection, groundwater was injected for about 2 months. Figure 4-14 presents a map that contours the percentage of total cumulative
sulfate pounds extracted in a one month period (45 days of bromide injection followed by
groundwater injection). During this time, 56 percent of the total bromide injected was recovered.
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Prepared by SRK, 2010
Figure 4-12 Contoured percentage of sulfate mass recovered during pre-leach groundwater injection test (3/12/1997). BHP-1 is the injection well.
Figure 4-13 Contoured percentage of sulfate mass recovered during raffinate injection and rinsing phase (10/31/1998 to 5/12/1998). BHP-6 through BHP-9 are injection wells.
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Figure 4-14 Contoured percentage of bromide recovered by well during bromide tracer test (5/13/1998 to 7/17/1998)
4.2.11 Flow and Transport Modeling
Numerical inverse modeling was used to calibrate hydraulic parameters in the oxide zone, based on
the field test results. The flow distribution was simulated using MODFLOW, a flow model
developed by the U.S. Geological Survey (McDonald and Harbaugh, 1988). The tracer movement
was simulated using MT3D, a transport model that considers advective and dispersive processes (Zheng, 1990). The inverse calculation was conducted using the Parametric Estimation software,
PEST.
To calibrate the parameters, an initial estimation of these parameters was put in the models. The results of the simulations were then compared with field data. If the match was not satisfied, the
hydraulic parameters were adjusted by PEST, and simulations were repeated until a satisfactory
comparison of field data and simulation results was achieved. The interference pumping test data
were used to calibrate the distribution of hydraulic conductivity. The water injection test data were used to calibrate the dispersivity, and effective porosity. Because of the heterogeneous nature of the
rocks, the calibration is usually non-unique. However, the major features within the area surrounded
by the wells will be captured.
The model grid covered an area of 7,000 feet by 7,000 feet within the test site and 640 ft of depth.
The grid design was characterized by non-uniform cell spacing of 10 feet (middle cells), 20 feet, 40
feet, 60 feet, 135 feet, and 140 feet, which encompassed the boundary of 7000 ft by 7000 ft. The wells were positioned in the inland block, separated (discretized) in 10 feet x 10 feet cells. The grid
perimeter cells were assigned constant head boundary conditions. The vertical dimension of the
model was discretized into 3 layers. The top layer covered the lower basin fill unit. The second
layer covered the top 40 feet of oxide. The bottom layer covered the rest of the oxide. All the layers were considered to be confined aquifers. The transmissivity values were allowed to vary and were
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calculated from the saturated thickness and hydraulic conductivity. The storage coefficients were
considered to be uniform.
The test area was divided into 37 distinct zones. A high conductive zone and two low conductive
zones were introduced along BHP-5 and BHP-9, based on the examination of pumping data and
tracer data as well as the geological features. Some zones were combined as one zone during the calibration process to reduce the number of parameters, in order to reduce the computation time and
enhance the certainty of calibration.
Figure 4-15 shows the field drawdown curves and the calibrated curves. The hydraulic conductivity results show a zone connecting BHP-5 and BHP-9 that has significant differences with the
surrounding rocks. The value of the high conductive zone was 5 ft/day, sandwiched by the low
conductive zones of as low as 0.1 ft/day. This feature indicated that there was a short circuit
between BHP-5 and BHP-9. The wellfield was separated into two somehow isolated areas.
The SO4 concentration curves of the calibration and field water injection test data are shown in
Figure 4-16. The dispersivity value obtained was 70 ft and the effective porosity was 6 percent.
This was consistent with the previous studies (Orr, 1997). The match was surprisingly good, considering that the dispersivity value and the effective porosity were treated uniformly. It was
found that introducing more zones of dispersivity and effective porosity only slightly improved the
match.
The bromide test was not used to calibrate the model because the bromide test was conducted after three months of leaching. The conditions of rock had been changed since the pumping tests and pre-
leach water injection test were conducted. However, the test was used to validate the numerical
simulations, as shown in Figure 4-17. The match is qualitatively good. The slower arrival time in test data indicates the porosity increased due to the leaching of minerals.
In summary, the approach of equivalent porous medium embedded significant discrete features
matches the field data very well in such a highly fractured and heterogeneous rock, as was found by Neuman (1982).
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Source: BHP, 1999, Comparison of observed (blue) and model simulated (pink) drawdown results, statistical data (yellow and cyan).
Figure 4-15 Field drawdown curves and the calibrated drawdown curves
BHP2
-2
3
8
13
18
1 10 100 1000 10000
minutes
BHP3
-2
3
8
13
1 10 100 1000 10000
minutes
BHP4
-2
3
8
13
1 10 100 1000 10000
minutes
BHP5
-2
3
8
13
18
23
1 10 100 1000 10000
minutes
BHP6
-2
3
8
13
1 10 100 1000 10000
minutes
BHP7
-2
3
8
13
1 10 100
minutes
BHP8
-2
3
8
13
18
1 10 100 1000 10000
minutes
BHP9
-2
8
18
28
38
1 10 100 1000 10000
minutes
BHP10
-2
3
8
13
1 10 100 1000 10000
minutes
BHP12
-2
3
8
13
18
1 10 100 1000 10000
minutes
BHP13
-2
3
8
13
18
1 10 100 1000 10000
minutes
OWB1
-2
3
8
13
1 10 100 1000 10000
minutes
OWB3
-2
0
2
4
6
8
1 10 100 1000 10000
minutes
OWB4
-2
3
8
13
18
1 10 100 1000 10000
minutes
OWB5
-2
3
8
13
1 10 100 1000 10000
minutes
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Source: BHP, 1999
Figure 4-16 Relative concentrations seen in sulfate field data and calibration results
Source: BHP, 1999
Figure 4-17 Simulated (magenta) and measured (dark blue) bromide concentrations in BHP-6, BHP-7, BHP-8, and BHP-9
-0.10
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0 10 20 30 40 50 60 70
day
rela
tive
co
nce
ntr
ati
on
BHP2 meas
BHP2 calc
BHP3 meas
BHP3 calc
BHP4 meas
BHP4 calc
BHP5 meas
BHP5 calc
BHP6 Br Test
-0.2
-0.15
-0.1
-0.05
0
0.05
0.1
0.15
0.2
0.25
0.3
0 5 10 15 20 25 30 35
Day
Rela
tive C
on
cen
trati
on
0
0.2
0.4
0.6
0.8
1
1.2
Weig
ht
Measured
Calculated
Residual
Weight
BHP7 Br Test
-0.05
0
0.05
0.1
0.15
0.2
0.25
0.3
0 5 10 15 20 25 30 35
Day
Re
lati
ve
Con
cen
tra
tio
n
0
0.2
0.4
0.6
0.8
1
1.2
Weig
ht
Measured
Calculated
Residual
Weight
BHP8 Br Test
-0.05
0
0.05
0.1
0.15
0.2
0.25
0.3
0 5 10 15 20 25 30 35
Day
Re
lati
ve
Con
cen
tra
tio
n
0
0.2
0.4
0.6
0.8
1
1.2
Weig
ht
Measured
Calculated
Residual
Weight
BHP9 Br Test
-0.05
0
0.05
0.1
0.15
0.2
0.25
0.3
0 5 10 15 20 25 30 35
Day
Re
lati
ve
Con
cen
tra
tio
n
0
0.2
0.4
0.6
0.8
1
1.2
Weig
ht
Measured
Calculated
Residual
Weight
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4.2.12 Hydraulic Containment Results
Injection of sulfuric acid solution started on October 31, 1997. The leaching solution was made of
groundwater from Florence, concentrated sulfuric acid from San Manuel, and San Manuel raffinate.
The injected solution had an average pH of 1.6.
The wellfield was operating at a total injection rate of 122 gpm and a total recovery rate of 150 gpm.
Table 4-5 presents the average injection and pumping rates for the wells. The rates declined with
time owing to the clogging of pumps. The pumping rate was kept low thereafter. The problem was
solved later by injecting raffinate around pumps to dissolve the precipitation on the pumps. Injection rates ranged between 21 to 35 gpm per well. Pumping rates in the inner recovery wells ranged
between 14 to 19 gpm per well. Pumping rates in the perimeter recovery wells ranged between 10 to
13 gpm. The total pumping rates have been kept larger than the total injection rates, based on permit requirements. The net pumping and injection rates are shown in Figure 4-18. BHP-1, which is
surrounded by the four injection wells, was the main recovery well and pumped at an average rate of
39 gpm.
The depth to water data for the BHP test wells and the six observation wells (OWB series) during the leach test on February 2, 1998 were used by SRK to create a groundwater elevation contour map.
The map shown on Figure 4-19 shows the hydraulic containment of the injection wells, BHP-6,
BHP-7, BHP-8, and BHP-9.
Table 4-5 Average injection and pumping well rates during leaching phase
Well ID Average Injection (gpm)
Well ID Average Pumping (gpm)
BHP6 32
BHP1 39
BHP7 35
BHP2 14
BHP8 21
BHP3 17
BHP9 33
BHP4 16
Sum 121
BHP5 19
BHP10 11
BHP11 11
BHP12 10
BHP13 13
Sum 150
Source: BHP, 1999
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Figure 4-18 Net positive pumping rate in the wellfield (BHP, 1999)
Source: Prepared by SRK in Surfer using February 2, 1998 BHP water level records
Figure 4-19 Potentiometric map for February 2, 1998 (contours in ft amsl)
Inflow vs. Outflow Rates
0
20
40
60
80
100
120
140
160
180
200
10/31/97 12/30/97 02/28/98 04/29/98 06/28/98 08/27/98 10/26/98 12/25/98 02/23/99 04/24/99
Rate
(g
pm
)Injectate to f ield
Total Flow from Field
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4.3 Conclusions and Lessons Learned
In general the hydrogeologic study of the mine site and of the pre-leaching 5-spot area addressed all
of the areas of concern.
4.4 Recommendations for New Field Test
Listed below are a few brief comments related to hydrological aspects of a future field test and full-
scale operations.
4.4.1 Data Management
Management of well construction data, water quality analyses, water levels, and equipment
installation and maintenance records will be an on-going concern in the future field test and during
full operations. Installation and development wells and their associated facilities will generate volumes of data that will be required for assessing the success of the ISR operation and to meet
ADEQ and UIC compliance requirements. A data collection plan and a Sampling and Analysis Plan
(SAP) must be developed to ensure all data are collected at the proper source, at the proper time, and
by the proper means. The plans need build on any available operations plans previously prepared to address normal operation and contingencies, such as device failures and power outages. The SAP
should address quality assurance methods water quality monitor wells including sampling, data
downloads, water level and other field measurements. Sampling personnel should be thoroughly trained in sampling protocols to ensure the quality of the program is maintained.
Data will be generated by hand entries into logs books, data capturing devices, and reports. The data
should be stored so that it can be easily accessed, can be uploaded simply, captures all required elements, is backed up, and secure.
Data Capture
Hand entry – Data that is hand entered is the likely to contain errors. Errors are potentially generated when the device is read, when the data are entered into the log, and when the logged data are entered
into an electronic file. Capturing and handling of data in this fashion should be minimized.
Handheld instruments used to capture data should have a data logger that can download to a computer.
Data capturing devices – Devices connected to equipment that automatically capture and record data
should have sufficient memory to store all data for the period of time between downloads plus a
reserve. The device also needs sufficient power to maintain full operations between battery replacements or external power outages. The devices must also be secured from the environment
(heat, wind, strong rain) and vandals.
Data reporting – Reports generated from laboratories should include an Electronic Data Deliverable file. These files should be received in a format that is easily uploaded to the sampling database and
has all information that may be needed including method detection limits, and potential issues with
interferences or varying dilutions that can occur when laboratories analyze process solutions.
Once data are received they should be verified for completeness, correctness, and conformance; then validated to determine its analytical quality. These two steps will ensure the data meets the
requirements of the data collection plan and the SAP.
A database provides the best means of storing, displaying, and reporting site data. Several commercial products are available that provide water quality database formats for analyses,
compliance exceedance alerts, graphs, mapping, scheduling, and reporting. These products are well
developed and tested. They can be installed, running, and operational in minimal time after some training. Another option is to use a commonly available database, such as Microsoft Access, which
would need to be tailored to the site requirements. Graphing routines, data entry forms, reports, and
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queries would need to be developed, and tested. This process tends to be time consuming and
involves staff members very familiar with input characteristics and output requirements to develop the database structure. Staff training is required for data input and a data supervisor is needed.
Owing to the inability to foresee all requirements, additional development is typically required.
Additionally, such systems do not possess some features that the more sophisticated commercial products offer, e.g. mapping, alerts, and scheduling.
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5 Geochemical Characterization The major source of information that can be used to interpret the progress of leaching reactions
within an in-situ wellfield is the composition of the effluent solution. These compositions must be
interpreted in conjunction with experimental and theoretical studies into the behavior of the various components during reactions with the various mineral associations present in the Florence deposit.
The test was terminated upon a successful demonstration of hydraulic control according to permit
requirements, but before economic copper leaching was successfully demonstrated. The copper recovery curve required for economic models must therefore be extrapolated from the results of this
test, through the use of a reactive transport model. This section provides the experimental and
theoretical background for the interpretation of the Florence field test geochemistry, the analytical data from the leaching and remediation portions of the test, and results of reactive transport model.
5.1 Summary of Metallurgical Test Work
Magma and BHP conducted numerous mineralogy, bottle roll, column leach tests, and chrysocolla
dissolution studies during their respective pre-feasibility studies (Appendix 3, Magma, 1995;
BHP1997d), which are briefly summarized below. Representative samples were selected for the test work by geologists familiar with the deposit rock types, mineralogy, alteration, and assay grade
populations. The metallurgical tests used NX/NQ-diameter drill core and 6-inch diameter drill core
and targeted the dominant rock types and grade ranges. Magma studies were designed to assess leach recovery and acid consumption under heap leach conditions; the tests were performed by
McClelland Laboratories, Inc. of Sparks, Nevada using small- and large-diameter drill core.
BHP’s pre-feasibility metallurgical program was initiated in 1996 to provide information for the
design and planning of the ISR operation. Representative samples selected for testing consisted of materials to be leached within the first 5 to 7 years of operation. The program was designed to
address technical issues that had been identified from previous work. These mainly consisted of
estimating the amount of copper-bearing minerals that could be contacted with acidic solutions and the geochemical behavior of fluid-rock interactions. The metallurgical program consisted of
mineralogical studies, cation-exchange experiments to evaluate the removal of copper from smectite
clays, bottle roll tests to determine copper mineral solubility and acid consumption in sulfuric acid lixiviant, and column leach tests to determine aspects of copper leaching, kinetics (time-recovery),
likely leach solution chemistry, and reclamation chemistry. Limitations in the column-test work
program and results were related to the inability to replicate completely the hydrologic conditions
and porosity existing in the saturated bedrock. Solution velocities, contact time, and fluid-to-rock ratios can be considerably different in unsaturated column tests or heap leach materials versus in-situ
conditions.
5.1.1 Summary of Previous Test Work
Development of the Florence copper resource was begun by Conoco in 1971, and various leaching
tests and mineralogical characterization studies were carried out by Hazen Research, Inc. from 1971
through 1974 (Conoco, 1976). Most of the Hazen work comprised bottle roll and mechanically agitated leaching tests. In about 1972, a decision was made to adopt vat leaching of finely crushed
copper oxide mineralization with a cut-off grade of 0.3% TCu. During 1972–74, the vat-leaching
concept was refined by tests that explored the influence of particle size, temperature, and free acid concentration on leaching kinetics. Recognizing the relatively brief duration of a commercial vat
leaching cycle (7 to12 days), the tests were focused on achieving 70–76 percent copper dissolution in
less than 10 days, and preferably 2–4 days, in the interest of minimum acid consumption. The Hazen
program concluded with a pilot-scale vat-leaching test in 1976.
In 1994, McClelland Laboratories, Inc. conducted 19 bottle roll tests and 4 column tests as part of a
study that was designed to compare the feasibility of an open pit, heap leach operation with in-situ
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leaching and recovery (Magma, 1994). The tests were made on drill core samples obtained during
the Magma pre-feasibility assessment and were intended to complement the Conoco effort. The bottle roll leach tests dissolved 40–80 percent of the total copper in the samples and approximately
65–75 percent dissolved during column leaching.
In 1995, 19 column tests were performed under the direction of B & C (1996) as a part of the work needed to apply for an Aquifer Protection Permit (APP). Seventeen of the tests examined the acid
neutralization capacities of various rock types and basin-fill sedimentary units. Two other column
tests were run in order to determine pregnant leach solution (PLS) composition after leaching at pH 1.5 with recycled SX raffinate. Head assays were not obtained, but the columns produced maximum
PLS grades of 3.8 grams per liter (g/L) and 8.4 g/L Cu and the estimated leachable copper content of
the samples equated to 0.56% Cu and 0.84% Cu, respectively.
The laboratory tests conducted by Hazen, McClelland, and B & C followed procedures normally used to enable scale-up of metallurgical response to conventional vat, heap, or agitated leaching and
generally did not yield data of direct use in designing in-situ recovery. For example, solution
flowing between injection and recovery wells must pass through typically 50 to 100 feet of mineralized formation without pH adjustment, whereas the early tests incorporated periodic acid
addition to maintain a nearly constant free acid concentration. Nonetheless, those tests did provide
useful information about response variability and maximum likely copper solubilization.
BHP set out to design experiments that would more closely simulate in-situ conditions by saturating the column sample with leaching solution, by using lower solution flow rates, and by altering
solid/liquid contact and fluid retention. The last two techniques were to involve coating large-
diameter core samples with epoxy and filling the cavities in the column charges with inert silica sand.
Chrysocolla (hydrous copper aluminum silicate) at Florence has been known for decades to have
variable copper content ranging from the theoretical concentration of 36.2 weight percent copper to a low of approximately 18 weight percent. Examinations by Adrian Brown Consultants, Inc.
(Williamson, 1996) as well as by Davis (1997) and Brewer (1998) revealed a highly variable
composition with aluminum ions typically substituting for copper in a layer silicate lattice. Some
mineral grains can contain only a few percent copper and will be only faintly bluish in color. During leaching with raffinate, the copper silicates initially dissolve congruently with silica until the
leaching solution becomes silica-saturated and only copper dissolution is favored. A rough
quantification of this type of mineralization versus the percent of copper-bearing mineralization located dominantly on fractures is noted for each assay interval in the drill logs and in the project
database.
5.1.2 Bottle Roll Tests
Bottle roll tests are bench-scale leach procedures designed to evaluate, rapidly and inexpensively, the
solubility of copper mineralization in a sulfuric acid lixiviant. Mineralization from the Florence
deposit had been analyzed with bottle roll leach tests during preliminary project evaluation by Conoco, and again with slightly different bottle roll tests during the Magma pre-feasibility study.
Sample material in both cases consisted of assay rejects from drill core; other parameters for each
type of test are presented in Table 5-1. The listed test parameter differences generally result in only
slight variations in the final copper recovery; the exception being the length of time each test is conducted.
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Table 5-1 Summary of test parameters for bottle roll tests
Variable Conoco Test Magma Test
Crush Size -6 mesh -10 mesh
Sample Mass 100g 500g
Solution Volume 1 liter 2 liter
Solution pH 1.0 1.5
Ending pH 1.1-1.5 1.5
Acid Content 10-12g/l 5-20g/l
Leaching Time 8 days 3 days
Source: BHP, 1999
The Conoco work demonstrated that copper mineralogy is a very important component to leach
recoveries of individual samples. This is reflected in the metallurgical zone (met zone) terminology that was an outgrowth of that early work. The metallurgical zones as described in Volume II,
Section 3 of BHP (1997a) consist of:
Zone 0: Overburden
Zone 1: Copper oxide-dominant mineralization
Zone 2: Mixed copper oxides and iron oxides
Zone 3: High iron, no visible copper oxides
Zone 4: Transition (copper oxides and sulfides)
Zone 5: Sulfide
A statistical summary of the Hazen and McClelland test results, grouped into metallurgical zones, is shown in Table 5-2. Both studies show that chrysocolla-dominated and mixed copper/iron oxide
mineralization (designated as Metzones 1 and 2, Table 5-1) exhibits relatively consistent copper
recoveries of around 65 to 70 percent of the total copper, with average copper grades of about 0.15 percent in the leached residue. However, the average acid soluble (ASCu) to total copper (TCu)
ratio of Magma samples is somewhat higher than the average ratio of the Conoco samples. This is
consistent with results discussed in Section 3.7.4, Volume II of BHP, 1997a, where it was found that the Magma/BHP Copper ASCu values are systematically higher than the Conoco ASCu values
obtained on the same pulp sample.
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Table 5-2 Statistical summary of bottle roll tests
A. Conoco bottle test data
Met Zone 1 2 3
Number 15 52 9
Avg. Std. Dev. Avg. Std. Dev. Avg. Std. Dev.
%TCu 0.633 0.390 0.554 0.389 0.284 0.063
%ASCu/%TCu 68.7 12.4 66.2 12.6 44.4 16.0
Bottle Rec. 72.2 12.6 65.0 13.8 43.3 16.2
Resid. Cu 0.136 0.087 0.158 0.129 0.140 0.040
B. Magma Pre-feasibility data
Met Zone 1 2 3
Number 0 16 1
Avg. Std. Dev. Avg. Std. Dev. Avg. Std. Dev.
%TCu 0.454 0.152 0.094
%ASCu/%TCu 79.2 7.5 56.7
Bottle Rec. 68.6 11.4 40.5
Resid. Cu 0.136 0.048 0.050
Source: BHP, 1999. Metzone 1 = chrysocolla dominant; Metzone 2 = mixed copper/iron oxides; Metzone 3 = high iron
A similar conclusion can be reached for material designated as Metzone type 3. The average recovery of the tests conducted by Conoco is nearly identical to the recovery of the one met zone 3
sample tested by Magma. The ASCu/TCu ratio of that Magma sample, however, is higher than the
average ASCu/TCu ratio of the Conoco samples. Nonetheless, the conclusion can be reached that
both the ASCu/TCu ratios and bottle test recoveries are significantly lower for met zone 3 samples than for met zone 1 and 2 samples.
Bottle test recoveries of chrysocolla mineralization are relatively independent of head grade for the
higher grade samples, and show 65 to 85 percent recovery for samples containing greater than 0.65 percent TCu. Chrysocolla-bearing samples below 0.65 percent TCu, along with met zone type 3
samples, tend to exhibit a poorly-defined grade-recovery relationship that could be approximated as
a constant tail recovery.
5.1.3 Large-Scale Column Tests
Four 6-in diameter by 10-ft high column leach tests were performed by Magma on crushed 1-in drill
core using San Manuel raffinate and 135 to 150 g/L sulfuric acid curd. Recovery rates of 64 to 73 percent were obtained under these conditions. Six-in diameter drill core was also used in a large
column (3 ft by 20 ft) using the same conditions with a calculated TCu recovery of 67 percent (BHP,
1997c).
Fourteen column tests were performed by the BHP San Manuel Metallurgical Lab and METCON Research in Tucson, Arizona. The materials tested included Magma and BHP drill core representing
primarily quartz monzonite with small amounts of granodiorite porphyry, diabase, and andesite; two
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columns tested primarily granodiorite porphyry. Column leach testing conducted since 1996 by
BHP was organized in three phases:
Scoping Phase: 60-day tests to determine raffinate-rock reactions and composition;
Phase I: determine leaching behavior of mineralization representative of the first mining area;
and
Phase II: evaluate alternative lixiviants.
The first four column tests, representing the Scoping Phase of the program, were conducted by METCON on minus 2-in sample. Columns 1, 2, and 3 began with de-ionized water that was acidified with sulfuric acid to concentrations of about 5, 10, and 20 g/L H2SO4, respectively,
whereas Column 4 was treated with raffinate from the San Manuel SX/EW plant. The head assays
of the quartz monzonite sample were 0.398% TCu, 0.058% S, and 1.51% Fe. The columns were
leached for approximately 60 days and copper was continuously removed by SX, but it should be noted that copper was still being dissolved at the end of the test period. It is also noteworthy that the
San Manuel raffinate with 80 g/L total sulfate had a leaching effectiveness (% copper dissolved)
mid-way between the results for 5 g/L and 10 g/L acid, despite containing only 2.9 g/L free H2SO4.
Of the four tests, as shown in Table 5-3, the 20 g/L H2SO4 leaching solutions used in Column 3
dissolved the most copper, but at the expense of higher acid consumption. The BHP metallurgists
concluded that the leaching solution containing about 10 g/L acid offered the best balance of copper
dissolution, acid consumption, and cation loading (summation of cation concentrations in the final raffinate). Therefore, the final PLS composition from Column 2 was used to synthesize raffinate for
the subsequent Phase I column tests. Table 5-3 summarizes the results obtained during the Scoping
Phase. Total solution applications averaged 16.5 pore volumes (PVs) or 4.08 liters/kg solids.
Table 5-3 Summary of results from scoping phase columns, METCON
Column #
Rock Type
Head Grade
Acid conc.,
g/L
Days % TCu Dissolved
lb acid per ton
lb acid per lb
Cu
1 QM 0.398 4.8 63 45.8 11.0 3.1
2 QM 0.398 9.7 63 54.5 17.2 4.1
3 QM 0.398 19.7 63 66.2 30.4 6.0
4 QM 0.398 2.9 63 48.7 7.6 3.3
Source: Compiled by SRK from BHP 1997d
The Scoping Phase tests were followed by Phase I column tests designed to examine copper leachability from samples representing major resource types. Columns A and B were run by the
BHP San Manuel Lab, and column tests 5-10 were performed by METCON. The sample origins
included 6-inch core from diamond drill holes MCC-534 and BHP-2, which were within the first
planned mining block. Synthetic raffinate was made according to the final PLS compositions of previous tests, but without copper. In Table 5-4, the origin of the synthetic raffinate is shown as
follows: that for Columns A and B resembled the composition of the final solution from column 2;
the final column A solution was synthesized to start columns 8 and 9. Usually, the initial raffinate was made by dissolving reagent-grade chemicals in de-ionized water. However, column 10 was
initiated with the solutions produced by columns 8 and 9. Column tests 5, 6, and 7 evaluated the
response of very low-grade mineralization with head assays, respectively, of 0.155% TCu, 0.164%
TCu, and 0.126% TCu.
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Table 5-4 Summary of results from Phase I column tests
Column Rock Type
Head Grade
%TCu
Raff
Source pH Days Pore Vols Liters/kg
% TCu
dissolved
lb acid
per ton
lb acid
per lb Cu
A QM 0.301 (calc)
2 1.4 84 13.0 4.40 35 2.5 7.6
B QM 0.141 (calc)
2 1.5 84 12.9 4.23 34 10.5 15.2
5 QM 0.155 2 1.5 59 12.9 3.49 46 16.6 26.0
6 QM 0.164 2 1.5 26 6.4 1.36 7 36.0 7.8
7 Tgdp 0.126 2 1.5 39 9.3 2.98 28 23.5 18.4
8 QM 0.216 A 1.7 158 35.2 8.00 54 1.6 43.7
9 QM 0.243 A 1.7 203 24.7 5.80 60 2.9 17.1
10 QM .305
(calc)
8+9 1.5 119 11.7 4.09 56 9.1 31.2
Source: Compiled by SRK from BHP 1997d
Columns 8, 9, and 10 were tested by METCON Research using average-grade, chrysocolla-bearing,
quartz monzonite (approximately 0.32 %TCu) from 6-inch diameter drill core; the voids were filled with inert sand (Col 8, 9) and tap was used prior to raffinate application to simulate saturated
conditions. The columns were 12-inch diameter by 5-foot tall (Col 8) and 12-inch by 10-foot tall
(Col 9 and Col 10); the material was subjected to simulated locked cycle in-situ leaching regime to assess the rate of copper dissolution and acid consumption. Leaching ranged from 158 days (Col 8)
to 203 days (Col 9); rinsing with tap water and a wash of sodium bicarbonate or sodium hydroxide
was performed following leaching. Copper extraction ranged from 54 to 56 percent with an acid
consumption ranging between 2.83 and 15.6 kg/metric ton of material (BHP, 1997c).
Although the tests were terminated when PLS copper grades were near or below 0.1 g/L, copper
recovery rates were still significant at the end of each test. This was because the relatively large
volume of leach solution that filled the column void spaces contains a relatively large mass of copper even at low copper concentrations. The copper recoveries attained during these column tests are
therefore not necessarily the maximum recoverable copper available for in-situ leaching and
recovery.
The Phase II column tests were designed to determine the efficiency of aluminum sulfate to pre-treat
typical chrysocolla mineralization for removal of exchangeable cations, specifically calcium and
copper. Copper recovery curves were similar to those illustrated in Figure 5-1, with relatively high
rates of recovery still present at the termination of the tests.
The columns were operated sequentially to simulate solution “stacking”, where low-grade PLS is
reconstituted with acid and returned to the formation in an effort to increase the PLS grade. The two
column tests were carried out at the BHP San Manuel Metallurgical Lab. The results are summarized in Table 5-5.
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Table 5-5 Summary of results from Phase II column tests, BHP San Manuel
Column Rock Type
Head Grade %TCu
Raff
Source
pH Days PVs Liters/kg % TCu
dissolved
lb acid
per ton
lb acid
per lb Cu
C QM 0.386 (calc)
A 1.5 133 31.8 7.25 52 1.77 7.08
D Mixed QM + Tgdp
0.296
(calc)
C 1.7 126 28.1 6.22 35 - -
Combined 3.30 10.13
Source: Compiled by SRK from BHP 1997d
The copper recovery values were compared to the total copper content that was estimated from
residue analyses and copper mass recovered in solution. Copper was still being extracted at the
termination of each column test, albeit at low copper values in solution. The copper recoveries resulting from column tests should not be considered the ultimate copper recovery, only those that
are measured under specific test conditions.
Recoverable copper estimates for the Florence ISR project are based on previous observations and
experiments conducted by a cohesive multi-disciplinary staff. Conceptually, copper recovery of in-situ leaching is very easy to estimate. When acidic solutions are placed in contact with chrysocolla
and are subsequently pumped from the ground, 100 percent recovery is attained. Estimating the
proportion of copper contained in a given volume of rock that meets those conditions is more complex and requires estimations the proportion of copper contained in fracture-controlled
chrysocolla, the proportion of those fractures contacted with acidic solutions and/or available to be
contacted, and the proportion of extracted copper that is contained in PLS of an economic grade.
Additionally acid generation potential, column leach, and attenuation studies were performed by B & C to assess environmental effects and to support the APP application process. The Magma/BHP
studies evaluated interactions among the various rock units present in the Florence deposit to assess
copper extraction, sulfuric acid consumption and raffinate chemical characteristics over time. Two types of column leach studies were undertaken: (1) to monitor reactions between acidic raffinate and
bulk rock samples and (2) to monitor reactions that simulated leach field remediation.
Geochemical simulations were performed by B & C (1996b) and BHP consultants (BHP, 1997d) to assess solution control, chemical reactions, mass balance, and water balance issues during
operations, simulate block closure, and assess the post-closure solute transport. The numerical
simulations will be briefly reviewed below.
The wellfield copper extraction and remediation simulations were performed for a 100-foot spaced 5-spot system, and at a flushing flow rate of 40 gpm, the background sulfate levels and neutral pH
were estimated to be achieved within 60 and 133-150 days respectively. Chemical and kinetic
transport simulations were undertaken using the same inputs, and the predictions were that it would take 15 years to achieve extraction of all copper available for recovery. It should be noted that the
kinetic model indicated that 50 percent of the recoverable copper could be achieved within the first
two years and that would include the fractured chrysocolla being consumed within the first year. The model was sensitive to porosity decrease which it predicted would approximate 50 percent in
two years and also to clay rate constants that with this basic system would increase the period for the
initial fifty percent recovery of available copper to five years.
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Source: BHP, 1997c
Figure 5-1 Copper recovery curves for column tests
5.1.4 Summary of Fracture Mineralogy Studies
A number of mineralogy studies were completed by to identify the principal minerals that would
interact with process solutions and to assess the potential for cation-exchange reactions. Mineralogy
examinations using X-ray diffraction (XRD) methods, scanning electron microscope (SEM),
reflected light microscopy, and semi-quantitative microchemical analyses were performed by J. Davis (1997) and C. Eastoe (1996) on exploration drill core and column test residues, respectively.
XRD-SEM Fracture Mineralogy
BHP geologist J. Davis (1997; BHP, 1997a) conducted a detailed study of the fracture mineralogy of the Florence deposit using samples collected from three drillholes located to the east of the field
test area. Using XRD and SEM techniques, they identified the minerals and assemblages present on
fractures as well as the distribution of different minerals vertically and horizontally.
The most common fracture minerals in the oxide zone are goethite (commonly copper-bearing), clay
minerals of various types (montmorillonite being most common, with lesser kaolinite, halloysite,
illite, and sepiolite), hematite, neotocite, jarosite, and chrysocolla. No horizontal variability was noted, and the vertical distribution appeared to be controlled by supergene processes.
The most common copper minerals observed were copper bearing-clays, but most of the copper in
the Florence deposit is present as chrysocolla of variable copper content. Copper-bearing clays
0 50 100 150 200Days Leaching
0
10
20
30
40
50
60
Co
pp
er
Re
co
ve
ry (
% o
f T
Cu
)
Col A
Col B
Col 8
Col 9
Col 10
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(mainly montmorillonite and kaolinite) were observed to have copper present in the octahedral site,
substituting for aluminum or magnesium; no intergrowths of clays and chrysocolla were observed.
Cation-Exchange Bottle Roll Tests
A series of bottle roll tests were conducted by BHP to determine the cation-exchange capacity of the copper-bearing clays present at Florence (Patel, 1996). Samples were taken from three drillholes
(MCC-543, MCC-551, and MCC-552) and run for 72 hours. Eleven different lixiviants were used;
these consisted of hydrochloric or sulfuric acid, combined with one of several ion-supplying agents
(chlorides and sulfates of barium, calcium, magnesium, copper, aluminum, and ammonium).
The tests showed that copper recovery was highest when aluminum sulfate was added to the sulfuric
acid lixiviant and that calcium ions in the calcium-montmorillonite clay exchanged readily. Copper
extraction during the 72-hour test was <1 percent for nearly all lixiviants except for the sulfuric acid plus alum. Copper extraction in screened, uncrushed samples treated with sulfuric acid plus
aluminum sulfate was 9.3% for the MCC-543 sample, 6.56% for the MCC-551 sample, and 5.93%
for the MCC-552 sample. Copper extraction in the crushed samples was greater, reaching 11.81%
for MCC-543, 8.6% for MCC-551, and 8.66% for MCC-552.
5.2 Geochemical Modeling
Several laboratory tests and numerical simulations were performed prior to and following the BHP
field test to assess mineral reactions and copper extraction rates during operations as well as the
water quality expected to be measured in the wellfield after rinsing was completed. The early simulations used the results of Column test 2 and theoretical chrysocolla dissolution values from
academic literature. The later simulations used the water quality data collected during the field test,
and an attempt was made to prepare a reactive transport model calibrated to the laboratory and field
measurements. A complete summary of the simulation results and interpretations was prepared by R. Preece and is incorporated as Section 5 in the draft Field Test Report dated October 15, 1999
(BHP, 1999). A brief summary is provided below of these simulations.
5.2.1 Summary of Pre-test Geochemical Modeling
Magma Copper recognized that copper recovery curves derived from laboratory-scale test work
could not be used to estimate field-scale production with simple scaling functions. Magma
contracted with Dr. Tianfu Xu, University of La Coruña, Spain and Dr. Peter Lichtner and co-workers at the Southwest Research Institute (SWRI), San Antonio for geochemical modeling. Both
Xu and Lichtner studies used the results from Column 2 to calibrate the models and to estimate
necessary mineralogical parameters to predict copper recovery curves. Work therefore began in mid-1995 by Magma to develop tools suitable for predicting and monitoring in-situ leach processes.
The reactive transport computer model was identified as being the most promising tool to allow for
scaling laboratory studies to production estimates. These models combine geochemical reaction equations with hydrogeologic flow and transport equations to calculate the movement of fluids and
their chemical components as they flow through reactive rocks.
5.2.2 Summary of Post-Leach Geochemical Modeling
Geochemical models of static reaction experiments demonstrated that the Florence field test data
could not be simply interpreted from any single mechanism. Furthermore, comparisons among the
models suggest that flow and transport are important considerations to any geochemical model for this particular field test. Finally, because the leaching portion of the field test was terminated before
full PLS breakthrough, the time-copper curve in the BHP-1 production well cannot be extrapolated
to predict the copper recovery and time-copper grade curves. These require the use of a reactive
transport model that incorporate fundamental hydrogeological and geochemical parameters obtained from the test data to extrapolate the results using a first principles approach.
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The problem was divided into two parts:
Dr. Denis L. Norton, a consulting geologist-geochemist, defined and estimated critical mineralogical and geochemical parameters from the behavior of injected solutions sampled at
monitor and production wells. This was largely conducted by examining the CH-2 data,
formulated as a one-dimension reactive transport problem.
Dr. Peter C. Lichtner, a consulting reactive transport modeler, used the parameters to first
calibrate the model against field data, and then extrapolate the test data to obtain a multi-year copper recovery curve. This was conducted as both a 2-D and 3-D problem, although a copper
recovery curve could only be obtained from the 2-D model.
Although good fits were obtained to the CH-2 geochemical data, the BHP-1 data were not successfully reproduced by the transport models. Because of project deadlines and inefficiencies
with working at long distances among the principals in this portion of the project, only a few
iterations were made to calibrate the model (BHP, 1999). Dr. Norton’s review suggested that
calibration may never be achieved under a conceptual framework of flow and transport through equivalent porous media, instead a hierarchical fracture network approach may be required.
The flow, transport, and geochemical parameters obtained from batch and column tests and one-
dimensional treatment of the field test were used by Lichtner (1999) to develop a production model for Florence. The work by Lichtner was divided into two phases: model calibration, in which 2-D
and 3-D models were constructed and compared with the field data; and production forecast, where
the best fit to the calibration phase was used to estimate a five-year copper recovery curve. Details of the problem setup and results are presented in Lichtner (1999), provided in BHP 1997d Appendix
IV-13.
The calibration effort was only partially successful. Only a limited number of models were run, and
fine-tuning of model parameters could not be accomplished. The profiles for monitor well CH-2 were reasonably well modeled, although transport parameters obtained from pumping and tracer
tests required modification to achieve this. Significantly, however, the geochemical behavior
observed in CH-1 and BHP-1 could not be reproduced. Use of a three-dimensional model that incorporated vertical variability in transport parameters did provide a possible explanation of the low
sulfate and magnesium values observed in these wells. Higher permeability and porosity in the
upper portions of the oxide zone caused a limited amount self-dilution as injected solutions migrated though the upper layer. Because of the higher porosity, these solutions were delayed in arriving at
BHP-1. Even so, Lichtner (1999) concluded that the present formulation of the flow and transport
was not suitable for satisfactory calibration of the model. Although Lichtner (1999) did not argue
for an alternative conceptual approach in the manner of Norton (1999c), he did recognize that a multiple continuum model was minimally necessary, coupled with a more complete understanding of
the flow characteristics.
It can be argued that the heterogeneity associated with fracture flow may be accentuated at the scale of a single five-spot. As a wellfield grows in size, use of a volume-averaged flow and transport
model may become more appropriate to simulate the overall behavior of multiple five spots. Using
this reasoning, a long-term forecast model was developed to estimate a copper recovery curve for the
Florence model. The two mineralogical cases discussed in the previous section were used to examine sensitivity of chrysocolla accessibility. In a similar manner as Lichtner, et al. (1996),
Lichtner (1999) distinguished the two types of chrysocolla by decreasing the kinetic rate for the
chrysocolla associated with copper-bearing clay minerals. Because of the difficulty with integrating the copper production over the vertical extent of the pumping well in the 3-D model, the forecast
model was conducted only for the 2-D case.
The copper recovery curves are presented in Figure 5-2 for the two cases. The difference in the ultimate recovery for the two cases is due simply to round off error in assigning chrysocolla
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concentrations in the initial boundary conditions. The five-year recovery is estimated to be
approximately 50 percent of the total copper for Case A, and 45 percent for Case B.
The PLS copper grade and pH curves for the two cases are shown in Figure 5-3. The values
predicted by the reactive transport model are consistent with values obtained in column and batch
test work, as well those observed in the CH-2 well. Because both cases obtain similar copper recoveries with the same flow rate, average PLS grades are similar to each other.
Source: BHP, 1999
Figure 5-2 Copper recovery curves of the long-term forecast model
The copper grade curve exhibited in this model would suggest that economic PLS grades could be obtained for 6 to 7 years of leaching. An economic cut-off grade of 200 to 400 mg/l is likely for an
intermediate leach solution suggesting that the Case A scenario could be leached for 6 to 7 years,
while the Case B would continue for 7 to 8 years (Figure 5-2). This extra leaching time would result in a copper recovery of 60 to 65 percent for both cases (Figure 5-2).
0 5 10 15
Time of Leaching (years)
0
20
40
60
80
Cop
pe
r R
eco
ve
ry (
% o
f T
Cu
)
67% Ultimate Recovery
CASE B
CASE A
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Source: BHP, 1999
Figure 5-3 Copper and pH curves from long-term forecast model. Case A production shown as solid lines, Case B shown as dashed.
5.3 Conclusions
The Florence field test was highly successful in achieving many of the engineering and hydrogeological goals that was set for the project. One very important accomplishment was the
successful demonstration of the ability to attain remediation of the wellfield. The project, however,
appears to have been constructed at an awkward scale to fulfill one of the basic goals of the project: demonstrate economic copper production at a field scale. Under production scale in-situ copper
extraction, such as the San Manuel in-situ facility (BHP property located approximately 50 miles
southeast f Florence) , several inter-connected production cells could be averaged to cancel the effect
of heterogeneity in the transport and chemical characteristics of the rock. With only one production cell, however, heterogeneity can dominate transport of reactive fluids in an unpredictable manner.
Even with this issue in the forefront, the test suggests that in-situ production is manageable by a
skilled team of geologists, hydrogeologists, and geochemists. The production planning team would adjust the wellfield layout to take advantage of or mitigate the effects of localized, site-specific
conditions based on experience gained in adjacent portions of the wellfield.
BHP’s geochemists felt that the geochemistry of the solutions recovered in production wells could not be explained solely on the basis of water-rock reactions. Only the solutions sampled in CH-2
followed expected geochemical behaviors, which were dominated by dissolution/precipitation and
cation exchange mechanisms. The geochemical evidence they believed pointed to a significant
amount of dilute solutions being mixed with raffinate in the remaining wells, even within the BHP-1 production well. No combination of known cation exchange, surface complexation, and
0
400
800
1,200
1,600
Co
pp
er
(mg
/l)
0 5 10 15
Time of Leaching (years)
0
2
4
6
8
pH
Copper Curves
pH Curves
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dissolution/precipitation mechanism was discovered that could explain the chemistry of production
wells without mixing with diluted waters.
The leaching portion of the test was not of sufficient length to demonstrate proof of concept for in-
situ copper extraction on a commercial scale. While copper leaching reactions were observed in
nearly all of the production wells, economic concentrations of copper in solution were not attained during the short duration of the field test. Of considerable concern were the apparently low recovery
rates that were calculated for the reaction path between BHP-6 and CH-2. This may be due to the
passive samplers in CH-2 intercepting a single flow channel rather than an integrated volume that would be sampled by a pumping well. The extent of water-rock reactions and dilution will be
important to assess in the new PTF.
Remediation of the wellfield is achievable, and appears to be strictly a function of using groundwater
injectate to flush raffinate from the groundwater system. Minor amounts of gypsum and silica appeared to have re-dissolved by the remediation fluids, but most components, including pH
appeared to behave conservatively. This conclusion was also reached on the basis of column
washing experiment by Preece (1997). This would suggest that the strategy of monitoring sulfate as a proxy for regulated components derived by B & C (1996d) continues to be a viable strategy. This
also suggests that adding a neutralizer to the injectate may not decrease the time necessary to meet
regulatory standards for pH.
5.4 Basis of Design
A copper recovery curve for the Florence project has not yet been demonstrated. Production model forecasts have been derived using curves calculated with reactive transport models that are largely
based on column and batch tests. Although leaching characteristics similar to these tests have been
observed in monitor well CH-2, this is an insufficient demonstration of project feasibility. Additional, longer term field-scale leach tests are required to provide a basis for copper recovery
curves.
The ultimate copper recovery for oxide zone mineralization by in-situ leaching technology was
estimated from geological observations and extrapolation of column leach tests. It was estimated, for the oxide mineral zones, that an average of 67% percent of the total copper is contained in
fracture-controlled chrysocolla (designated as CuOx1 in the drillhole codes) or copper-bearing clay
minerals (designated as CuOx2) within close distance of a fracture. The residual copper has been found in relatively insoluble copper-bearing iron hydroxides and in pervasive chrysocolla, copper-
bearing clays, and copper sulfides located in away from a fracture or in other zones or portions of the
deposit that are inaccessible to raffinate solutions. Like all ISR operations, this estimate will not be validated until a field-scale field test is run to completion. However, the time scale to completion for
an ISR operation is a matter of years, rather than months observed in oxide heap leach operations.
This estimate may not be completely validated by a feasibility-stage leach test, although the
proportion of copper contained in fractures and primary flow features (CuOx1) may be determined by a sufficiently long test.
Net acid consumption was estimated from column leach tests to be 3 lb. acid per lb. copper. While
free acid breakthrough (pH < ~3.5) was not achieved in any of the production wells, the Cu-pH relationships observed in the CH-2 monitor well are nearly identical to those observed in the column
tests. Because of the uncertainties in the interpretation of the leach test transport and reaction
processes, the acid consumption estimates from column tests could not be verified. It is also
uncertain whether the field-scale test provides an accurate indication of acid requirements for free acid breakthrough.
One cautionary note, however, was provided by leaching experiments with LBFU sediments. The
calcareous sediments overlying oxide zone mineralization were found to be calcareous, with acid
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consumption on the order of 150 lb acid per ton. Unintentional flow of raffinate into the LBFU will
increase acid costs if it is not effectively controlled by the well construction design and operation.
The ability to remediation an ISR site has been demonstrated in the BHP field test. The data
collected during the remediation portion of the field test indicates that sulfate levels in process water
are a good indicator of the concentrations of ADWR-regulated constituents. Dissolved sulfate of approximately 750 mg/l denotes that most constituents are near or below regulatory limits. The one
exception is pH, where rinsing of more 99 percent of the PLS is required before regulatory
compliance. The current data suggest that this is strictly flow driven, so that non-reactive transport models may be sufficient to use for estimates of water balance and remediation time and costs in the
process flow sheet.
5.5 Recommendations
The Florence ISR test must be re-done. The field test program completed to date is not sufficient to
state mineral reserves based on known total copper recovery or rates of copper recovery. However, it is not recommended that the test be conducted under the same conditions, however, as it is likely
that the same results will be obtained. In particular, it is recommended that additional wells be
drilled to provide multiple leaching cells.
The amount of dilution required by geochemical models has not been successively simulated by flow and transport models constructed to date. Conversely, the chemical reaction paths that are implicit in
the transport models are incompatible with static and transport reaction models discussed in this
study. This duality between the geochemical and hydrogeological view of the test data must be at least conceptually reconciled before attempting a second leach test. The concepts advanced by
Norton (Appendix VI-13) provide a good starting point to a working toward a new paradigm.
Additional simulations of field-scale extraction and remediation should be conducted. In particular, the effect of variable copper content of the wellfield on PLS copper grade and total leach time should
be investigated. The remediation of the wellfield provided a useful, longer term data set that may be
used for inverse modeling of the transport characteristics of this wellfield. It also provides for
forwarding modeling efforts to better understand the dynamics of fluid dilution and back-reaction of precipitates during remediation. These may help to better design the next test field and remediation
strategies.
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6 Operations Activities through Reclamation Phase Section 6 provides information on the field test operation with respect to changes in water quality
through time.
6.1 Field Test Duration
The leaching and reclamation schedule for the BHP field test is shown in Table 6-4. An injectate consisting of sulfuric acid and WW-4 groundwater only was injected on Day 1; injection of San
Manuel raffinate and groundwater began on November 1, 1997 and continued through February 6,
1998. Injection of pond water only followed by groundwater only was performed BHP-6 through BHP-9 through May 12, 1998 with simultaneous recovery of increasingly dilute solutions in the
remaining recovery wells. Groundwater injection was performed in BHP-1 through December 16,
1998 with water recovery in the former injection wells. Pumping of BHP-6 through BHP-9
continued through March 31, 1999.
6.2 Field Test Operation Procedures
During the field test, well data was collected manually and electronically from individual injection,
recovery, and monitoring wells, tanks, and pond levels. This information included: water levels,
electrical conductivity and pH, flow rates, and the chemistry of injected and recovered solutions and groundwater.
6.3 Manpower Requirements and Duties
The original staffing plan was to have six full-time employees in the wellfield during the field test
including two technical supervisors with four additional full-time shift workers working as operators.
One new hire quit just before operational start-up, and one technical supervisor died in a car accident the week after start up, so the field test was operated by Michael Kline and three other operators,
with maintenance by Peter Kelm and Richard Sichling (safety officer). The staff worked two 12-
hour shifts each day on a 28-day rotating shift schedule; the shift changes occurred at 6:30 a.m. and 6:30 p.m. No regular time for lunch period or break period was set up, allowing the technicians to
decide on their own when to take lunch and rest breaks.
Full-time coverage, however, was needed for two important reasons. The first reason was to have
enough staff to watch the delivery truckers when offloading the raffinate, and sulfuric acid, and caustic soda to ensure safe procedures were used. Second was to watch for power outages and do
the manual switch-over to back-up power during seasonal storms, this was required at least six times
during the 101 days (M. Kline, written commun., 2010). Sampling, sounding, and performing pH and conductivity measurements only took about 6 hours of the operator’s duties. If major
maintenance work in the wellfield or evaporation pond had to be done, however, it could not be done
by a single operator. Maintenance problems were also caused by seasonal monsoon events during strong wind, rain, and lightening.
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Table 6-1 Field test shift schedules
Shift Mon Tue Wed Thu Fri Sat Sun
Week 1
Day 4 4 4 3 3 3 3
Night 1 1 1 1 4 4 4
Week 2
Day 1 1 1 4 4 4 4
Night 2 2 2 2 1 1 1
Week 3
Day 2 2 2 1 1 1 1
Night 3 3 3 3 2 2 2
Week 4
Day 3 3 3 2 2 2 2
Night 4 4 4 4 3 3 3
Source: M. Kline, personal commun., 2010
6.4 Evolution of the Water Quality in the Field Test through Rinsing Phase
Water quality samples related to the BHP field test consisted of groundwater monitored before and
after the field test and the make-up water pumped from well WW-4. Water quality samples related to process solution included injectate (the mix of groundwater and sulfuric acid injected into the
injection wells), pregnant leach solution collected from the recovery wells, and the evaporation pond
water. Process solution samples were taken daily and weekly by field technicians trained in water quality sampling procedures. Water quality analyses were performed by the BHP Copper San
Manuel Metallurgical Laboratory, ACTLABS-Skyline of Tucson (now Skyline Assayers &
Laboratories), and ACTLABS-Enzyme (now ACTLABS) of Ancaster, Ontario, Canada. Field data
(water level, electrical conductance, and pH) were recorded and entered by BHP field technicians on a daily basis.
The groundwater and process solution analyses related to the field test and subsequent rinsing phase
are available in a Microsoft Access database (FlorenceDB.mdb-revised 6/28/2010) for the period from November 1, 1997 through October 1999. Although the number of sampling points decreases
after March 1998, sampling data are also available from 2000 through 2007. The database contains
records of water quality sampling, well construction and well history details, flow data, the results of mechanical integrity tests, and other information. Data entry forms, queries, and reports that
generate graphical views of the concentrations of constituents for various sets of wells are also
available in the database. The data were originally entered by BHP employees to record the results
of drilling (well construction details, costs, integrity tests) and the results of solution analyses related to an in-situ leach, recovery, and rinsing field test.
The water quality database lacks standard laboratory quality assurance/quality control (QA/QC)
information such as minimum detection limits, date of analysis, dilution factors, QA/QC codes/comments, etc. SRK found some apparent data entry errors and outlier results in the Access
database but did not cross-checked the database entries against the original laboratory sheets or field
record sheets to estimate overall accuracy or completeness of the database. An effort was made
through the sampling program to collect duplicate samples and to record the meter calibration results.
Graphical interpretation and presentations of the water quality data were prepared by BHP and have
also been prepared by SRK in an attempt to understand the interactions and recoveries in each well and in groups of wells. Wellfield extraction graphs are shown in Appendix A and water quality
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graphs for each well are shown in Appendix B. The graphs quickly become too busy to interpret
easily and the horizontal and vertical water quality changes occurring through time in the injection and recovery wells is not easy to understand using standard Excel graphs.
To provide a more spatial and temporal interpretation of the solution chemistry and understand the
reactions that occurred, the data were exported from the Access database into Voxler2 by Golden Software, a 3-D gridding/contouring software program. The concentrations between known points
were kriged to estimate water quality concentrations within and adjacent to the field test area. An
animation was created on the kriged concentration results to show the evolution of water quality through the duration of the field test. A full explanation of the methods was provided to Curis is a
separate memo (SRK, 2010a)
6.4.1 Sulfate
The wellfield layout and well traces are shown in perspective view in Figure 6-1. Sulfate
concentrations were interpolated by day on a weekly basis, displayed with cutoff grade colors, and
captured as jpg images for display. Examples are shown in Figure 6-2 at two dates—November 7,
1997 and February 1, 1998. The injectate, a mix of raffinate and local groundwater, had a concentration of approximately 10,120 mg/L SO4 when it was injected via BHP-6, BHP-7, BHP-8,
and BHP-9 beginning October 31, 1997. The injectate concentration varied and was approximately
6,387 mg/L in early February.
Note the early detection of elevated sulfate in perimeter recovery well BHP-5 one week into the test
while other perimeter recovery wells were still measured below 1,000 mg/L (concentrations less than
1,000 mg/L are shown in white). Near the end of the test, elevated sulfate was uniformly measured throughout the field test with the exception of upgradient, perimeter recovery well BHP-13 where
continual inflow of fresh groundwater prevented concentration of the sulfate. Upgradient well BHP-
2 showed markedly lower concentrations and mass of copper extracted than upgradient well BHP-5
suggesting that some structure or other feature preferentially directed flow from BHP 9 to BHP-5.
Figure 6-3 shows the rinsing progress that was achieved during the following two months based on
sulfate concentrations and pH. The intermediate pH, residual process water in the evaporation pond
was injected back into the test area via the same four injection wells from mid-February to March 21, 1998. Groundwater from WW-4 was injected into the test area until May 14, 1998. The upgradient
portion of the field was rinsed to below 1,000 mg/L in less than two months.
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The injection wells are shown with yellow drillhole collars, recovery wells have green collars, and chemical monitor wells have white
collars. The white drillhole traces are shown in perspective view using downhole surveys.
Figure 6-1 Planar view showing field test layout and location of the wells in mine coordinates (ft)
Note: Sulfate concentrations vary from background values of less than 1,000 mg/L (shown in white) measured on the perimeter of the test
area to high sulfate values of over 6,000 mg/L measured in injection wells BHP6, BHP7, BHP8, and BHP9 (shown in red).
Figure 6-2 Planar view showing SO4 (mg/L) concentration near the start of raffinate injection on November 7, 1997 (left) and end on February 1, 1998 (right)
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Figure 6-3 Planar view showing SO4 (mg/L) concentration at the end of pond water injection on March 21, 1998 (left) and the end of groundwater injection on May 14, 1998
6.4.2 pH
The pH visualization begins with a perspective view looking down from immediately above the field test area and transitions to an east-west profile looking north. Background groundwater quality
ranges from pH7 to over pH8 as shown in the plan view in Figure 6-4. During the raffinate injection
phase, pH values ranged from approximately 1.5 to 1.7 in the injectate. Although pH values have a lognormal relationship, the values were treated as integers in this simplified approach and were
interpolated using IDW2 method with 50’ projection distances. Images were created for weekly
results using cutoff grade colors for values ranging from pH1 to pH9. Injectate is visible as red color
in the visualization and in Figure 6-4 and Figure 6-5.
In the animation, you will note the steady decrease in pH spreading outward from injection wells
BHP-6 and BHP-8 first at the upper elevations, then middle, and lower one-third of the profile.
Starting in the last week of January, the central recovery well has finally reached the pH3.5 to pH3 level where copper dissolution can begin. It took more than 3 months for the injectate to migrate
across a 50-foot distance through rock of variable fracturing and hydraulic conductivity, partially
consume the carbonate gangue minerals present on the fractures, and start to reach a state of acid
equilibrium in the central test area that could overwhelm the inflow of fresh (pH 7-8) groundwater. This visualization, in conjunction with one on copper concentrations measured through the test,
emphasizes the time component needed to move enough volume of injectate across the flow path
between injection and recovery wells and through the volume of rock in order for the rock and pore solutions to start to become acid-equilibrated. Without acid-equilibration, copper cannot be
effectively dissolved and recovered.
The location of the injection wells in are clearly identified by the trace of low pH (1.5) solutions contoured in red color on left with near-neutral water in the vicinity of BHP-1 and neutral, pH7
water inflowing into the perimeter recovery wells. At the end of the test, the injectate has reacted
with materials in the top one-third of the rock profile and is decreasing to pH4 (yellow) in the bottom
portions of CH1 and CH2. Near-neutral water is measured in perimeter well BHP12.
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Note the background water quality has a pH between 7 and 8. On November 3, injection of pH1.5 injectate is visible in BHP-6, BHP-7,
BHP-8, and BHP-9.
Figure 6-4 Planar view showing pH (su) on October 31, 1997 (left) and November 3, 1997 (right)
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The well traces are faintly visible and begin at the top of bedrock.
Figure 6-5 Vertical E-W profile from BHP12 though BHP10 looking north showing pH on November 7, 1997 (left) and at the end of the raffinate injection phase (February 8, 1998)
During the rinsing phase, intermediate (4.8 to 6.05) pH pond water was reinjected back to the wellfield and the water quality recovered in the central and perimeter showed a similar range of pH
values (Figure 6-6). On March 14, the visualization shows a sudden decrease in pH measured in
BHP-10; this occurred when acidic injectate was used to kill and remove organic growths on the well
screen. Continued injection through May 14 with fresh groundwater had increased the pH from pH4.95 to over pH7 in the perimeter wells. Low pH concentrations ranging from 4.5 to 5.5 are noted
in the animation in the CH wells at the end of the three-month rinsing phase.
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At the end of the March, the injectate has reacted with materials in the top one-third of the rock profile and is increasing to pH4 (yellow) in
the top portions of CH1 and CH2. Water with a pH of 5-6 is measured in perimeter well BHP12. By the mid-May, pH values had
increased to the range of 5-8 for much of the wellfield with background values measured in injection well BHP-8. CH1 and CH2 still
show lower pH values between 4 and 5.
Figure 6-6 Vertical E-W profile from BHP-12 though BHP-10 looking north showing pH on March 21, 1998 (left) at the end of pond water injection and at the end of the groundwater injection phase (May 14, 1998).
6.5 Copper Recovery and Mass Balance
As previously discussed, the injectate was raffinate from the BHP San Manuel SX-EW Plant that
was mixed with site groundwater from well WW-4 to create an injectate solution. The concentration
of various trace inorganic metals and common ions varied in each batch of raffinate shipped to the
site. The average pH of local groundwater was 7.6-7.8 s.u; the average pH of the blended injectate was 1.65 s.u. The copper content in groundwater was approximately 0.1-0.2 mg/L; copper
concentration in the blended injectate ranged from 1 to 32 mg/L with an average 11 mg/L.
During rinsing activities, pond water with an average pH of 5.70 s.u. and copper content of 20 mg/L was injected back into the wellfield. Groundwater from WW4 was injected for the period from April
7 to May 12, 1998 as the final reclamation of the 5-spot leach area. The pH of the injectate during
this phase was approximately 7.41 s.u. with an average copper content of 0.2 mg/L.
A daily average for the flow rates (gpm) in and out of each well was matched with water quality
analyses for each well to calculate how much mass of copper was extracted from the wellfield.
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Interpolated values were used to fill the gaps later in the test when daily flows were available but
water quality analyses were performed only on a weekly basis.
Table 6-2 tabulates the copper (lbs) added to the wellfield by well through May 1999 via the
injection wells and extracted from the recovery wells. The majority of copper was added through the
introduction of the residual copper during the raffinate injection phase and through reinjection of pond water beginning in February 1998. The copper mass injected and extracted in units of
pounds/day through May 1998 and May 1999 is shown on Figure 6-7 and Figure 6-8, respectively.
The figures show the daily and cumulative lbs/day of copper injected into the four injection wells and pumped from the recovery wells during the leaching and reclamation periods. The slope of the
Net Daily Cu lbs/Day data line for the raffinate injection period between October 17, 1997 and
February 8, 1998 continued to increase until the premature cessation of the field test. A change in
slope is also seen in the daily and daily net recovery between January and February 1998 as seen in Figure 6-7; this may be attributed to the introduction of copper-bearing, intermediate pH pond water
in the make-up water and the decreased ratio of raffinate to injectate.
The total cumulative copper mass extracted from the wellfield was 41,966 lbs through May 1999 (14 months after the cessation of the raffinate injection phase). The net cumulative copper recovered
after the subtraction of copper contained in the injectate was approximately 39,743 lbs through May
1999. Approximately 2,223 lbs of copper (5.2%) was injected into the wellfield and not recovered –
probably through precipitation in fractures or in the montmorillonite minerals during the injection of copper-bearing pond water. The net copper recovery represents a small fraction (3%) of the 1.34
million lbs copper estimated to be contained in the volume of rock within the inner recovery cell
shown in Figure 2-8.
Table 6-2 Mass of copper injected and recovered during leaching and rinsing phases
Well Cu Injection (lbs)
Cu Extraction (lbs)
Net Cu
Extraction (lbs)
BHP-1 9 5,874 5,865
BHP-2 0 234 234
BHP-3 0 1,004 1,004
BHP-4 0 916 916
BHP-5 0 6,738 6,738
BHP-6 617 5,383 4,766
BHP-7 687 6,562 5,875
BHP-8 353 4,812 4,458
BHP-9 557 7,282 6,725
BHP-10 0 2,007 2,007
BHP-11 0 833 833
BHP-12 0 301 301
BHP-13 0 22 22
Total 2,223 41,966 39,743
Compiled by SRK, 2010 from BHP flow and water quality data for period of 31 October 1997 through 11 May 1999. Negligible copper
was added during groundwater injection phases.
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Figure 6-7 Daily and cumulative injection and extraction – Net copper (lbs) recovery vs. time through May 11, 1998
-10
1990
3990
5990
7990
9990
11990
13990
15990
17990
-10
10
30
50
70
90
110
130
150
170
190
10/31/97 11/21/97 12/12/97 1/2/98 1/23/98 2/13/98 3/6/98 3/27/98 4/17/98 5/8/98
Cu
mu
lati
ve C
op
pe
r Ex
trac
tio
n l
bs/
Day
Dai
ly C
op
pe
r Ex
trac
tio
n l
bs/
Day
Date
Total Wellfield Cu Extraction Per Day vs TimeField Test 1997-1998
Total Well Field lbs/Day lbs/Day Injected Net lbs/Day Cu Total Well Field Cumulative lbs/Day Cumulative lbs/Day Injected Cumulative Net lbs/Day Cu
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Compiled by SRK, 2010 from BHP flow and water quality data
Figure 6-8 Daily and cumulative injection and extraction – Net copper (lbs) recovery vs. time through May 12, 1999
6.6 Sulfate Recovery and Mass Balance
As was done with copper extraction, the flow rates (gpm) in and out of each well were matched with analyses in mg/L for the well. Interpolated values were used to fill the gaps later in the test when
daily flows were available but water quality analyses were performed only on a weekly basis.
During operation of the leaching phase of the test, sulfate content in the injectate ranged from 1,650 mg/L to 12,540 mg/L. The average sulfate content was 7,758 mg/L although the average decreased
during the test as the ratio of raffinate in the injectate decreased. During the pond water injection
phase, sulfate concentration in injectate ranged from 19 mg/l to 3,054 mg/L with an average of 1,783 mg/L. During the rinsing phase when WW-4 groundwater was injected, the sulfate content in the
injectate ranged from 10 mg/l to 452 mg/L with an average concentration of 85 mg/L.
The mass of sulfate injected and extracted is tabulated in Table 6-3 shown on Figure 6-9. As shown,
daily injection exceeds daily extraction through the leaching phase, but continues to be extracted after the leaching phase has ended. Cumulatively, approximately 1,168,496 lbs of sulfate was
injected into the field with a net recovery of 1,044,046 (89.3%) through May 11, 1999 when matched
sets of flow and assay records cease. Records compiled by BHP through June 2001 (Kline, 2001) show that 1,146,401 lbs of sulfate had been recovered with a net accountability of 98.6 percent.
Add more of John Kline’s info here
2/8/1998 5/12/1998 11/25/1998 5/11/1999
-10
4990
9990
14990
19990
24990
29990
34990
39990
44990
-10
40
90
140
190
240
Cu
mu
lati
ve C
op
pe
r Ex
trac
tio
n l
bs
Dai
ly C
op
pe
r Ex
trac
tio
n l
bs/
Day
Date
Total Wellfield
Cu Extraction Per Day vs TimeField Test 1997-1998
lbs/Day Extracted lbs/Day Injected Net lbs/Day Extracted Cumulative lbs/Day Extracted Cumulative lbs/Day Injected Net Cumulative lbs/Day Extracted
Raffinate Injection InjectionBHP1-5 & 10-13 Recovery
BHP1 GW Injection Phase Variable Recovery Wells
BHP6-9 Recovery
End of Injection
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Table 6-3 Mass of sulfate injected and recovered during leaching and rinsing phases
Well SO4
Injection (lbs)
SO4 Extraction (lbs)
Net SO4 Extraction
(lbs)
BHP-1 5,454 205,273 199,819
BHP-2 0 31,989 31,989
BHP-3 0 62,677 62,677
BHP-4 0 68,165 68,165
BHP-5 0 131,489 131,489
BHP-6 318,750 100,090 -218,660
BHP-7 349,828 110,556 -239,272
BHP-8 206,751 80,539 -126,212
BHP-9 287,712 124,977 -162,736
BHP-10 0 53,164 53,164
BHP-11 0 29,435 29,435
BHP-12 0 29,946 29,946
BHP-13 0 15,746 15,746
Totals 1,168,496 1,044,046 -124,449
Compiled by SRK, 2010 from BHP flow and water quality data for period of 31 October 1997 through 11 May 1999
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Compiled by SRK using BHP flow and water quality data
Figure 6-9 Mass injection and extraction - Net sulfate recovery vs. time through May 12, 1999
6.7 Conclusions and Lessons Learned
To Do
6.8 Recommendations for the New Field Test
Text
2/8/1998 5/12/1998 11/25/1998 5/11/1999
-1000000
-500000
0
500000
1000000
1500000
-25000
-20000
-15000
-10000
-5000
0
5000
10000
15000
20000
25000
Cu
mu
lati
ve S
ulf
ate
Ext
ract
ion
lb
s
Dai
ly S
ulf
ate
Ext
ract
ion
lb
s/D
ay
Date
Total Wellfield
SO4 Extraction Per Day vs TimeField Test 1997-1998
lbs/Day Extracted lbs/Day Injected Net lbs/Day Extracted Cumulative lbs/Day Extracted Cumulative lbs/Day Injected Net Cumulative lbs/Day Extracted
Raffinate Injection
InjectionBHP1-5 & 10-13 Recovery BHP1 GW Injection Phase
Variable Recovery WellsBHP6-9 Recovery
End of Injection
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Table 6-4 Timeline for leaching and reclamation activities
From To BHP-1 BHP-2 BHP-3 BHP-4 BHP-5 BHP-6 BHP-7 BHP-8 BHP-9 BHP-10 BHP-11 BHP-12 BHP-13
10/31/97 2/8/98 Prod Leach
Prod Leach
Prod Leach
Prod Leach
Prod Leach
Injection Raff
Injection Raff
Injection Raff
Injection Raff
Prod Leach
Prod Leach
Prod Leach
Prod Leach
2/9/98 2/17/98 Inactive Prod Recl
Prod Recl
Prod Recl
Prod Recl Inactive Inactive Inactive Inactive
Prod Recl Prod Recl Prod Recl
Prod Recl
2/18/98 3/26/98 Prod Recl
Injection Pond
Injection Pond
Injection Pond
Injection Pond
3/27/98 4/6/98 Inactive Inactive Inactive Inactive
4/7/98 5/12/98 Injection GW
Injection GW
Injection GW
Injection GW
5/13/98 7/17/98 Injection GW
Prod Recl Prod Recl Prod Recl
Prod Recl Inactive Inactive Inactive
7/18/98 8/5/98 Inactive Inactive Inactive
8/5/98 11/5/98 Inactive Inactive
11/6/98 11/12/98 Inactive
11/13/98 12/16/98 Injection GW
12/17/98 1/7/99 Inactive
1/8/99 2/7/99 Inctive Inctive
2/8/99 2/25/99 Prod Recl Inctive
2/26/99 3/5/99 Inctive Prod Recl
3/6/99 3/31/99 Prod Recl
4/1/99 5/12/99 Prod Recl
Notes: Inactive = Well not in operation
Injection Raff = Injection well during leach test, injectate is blend of raffinate and WW4 groundwater, low pH
Injection Pond = Injection well post-leach test, injectate is residual process solution in Evaporation Pond, intermediate pH
Injection GW = Injection well post-leach test during reclamation phase, injectate is WW4 water, neutral pH
Prod Leach = Production/recovery well during leach test
Prod Recl = Production/recovery well post-leach test during reclamation period
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7 Environmental and Safety Findings Section 7 addresses environmental and safety related issues during the field test and environmental
risk factors for post-closure water quality.
7.1 Environmental Issues during Operation of Field Test
Text
7.2 Environmental Issues following the Test - Post-Rinsing Water Quality
Routine water quality samples were collected during the field test and with decreasing frequency
through May 12, 1999 – one year after the conclusion of the pond water injection phase. Thereafter,
the pumping operation ceased. A set of water quality analyses was taken by B & C on behalf of
BHP in 2000 and 2001 and sent to Nevada Environmental Lab, Aerotech Laboratory, and Radiation Safety for analysis (see Table 7-1 and Table 7-2). B & C sampled the wells again in 2003 and 2007
as shown in Table 7-3 through Table 7-5.
Modeling performed by B & C (1996b) and previously submitted to ADEQ in the Magma APP application indicated that the regulated constituents sampled from within the aquifer exemption zone
would be below the Arizona Aquifer Water Quality Standards (AWQS) once the sulfate
concentration was rinsed to below 750 mg/L. In the fourth quarter of 2000, sulfate ranged from background values of 64 to 160 mg/L in the outer perimeter wells to slightly elevated values of 450
to 540 mg/L measured in the former injection wells BHP-6 through BHP-9. Neutral water quality
was measured in all wells except the former injection wells – pH values ranged from 3.83 in BHP-6
to 4.68 in BHP-8. By mid-2007, sulfate concentrations in the wells had all decreased to background concentrations with approximately 75 mg/L in the perimeter wells and 145 mg/L in the former
injection wells; pH in the former injection wells, however, had increased only slightly to 4.35 in
BHP-6 and to 5.11 in BHP-8. None of the trace metal results exceed the relevant AWQS at these sulfate and pH concentrations.
Radiochemicals were also sampled during leaching and rinsing phases, but with much less frequency
or consistency in constituents analyzed. Elevated adjusted gross alpha particle activity was
identified in five wells in 2001 including BHP-2, BHP-6, BHP-11, BHP-12, and BHP-13. A significant component of these analyses is contributed by total uranium, which was measured in
elevated concentrations ranging from 18.1 mg/L in BHP-8 to 10.9 p in BHP-12. Fewer analyses are
available in 2003 and 2007; three samples in 2003 (one in 2007) showed slightly elevated results ranging from 10.3 to 14.8 pCi/L but none of the analyses exceed the AWQS for adjusted gross alpha.
As seen before, the major constituent contributing to the elevated gross alpha is the total uranium
concentration. Total uranium is a constituent commonly noted in groundwater associated with the 1.4 billion year old granite and quartz monzonite basement rock in southern Arizona.
7.3 Safety Issues
BHP required that BHP employees and contractor personnel be MSHA certified. All personnel
received site safety, environmental, and cultural resources training prior to performing site activities
and mobile radios were used for communications in the field and to personnel in the Admin building. Regular safety training and tailgate sessions were performed primarily by Project Manager J. Kline,
Safety Supervisor R. Sichling, Sr. Technician J. McBroom, and Technician M. Kline. Fire safety
training exercises were prepared by R. Sichling, a volunteer Florence fireman. A program was instituted to report and respond to near-miss incidences, and adjustments made to avoid repeat
incidences.
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Safety issues changed over time from a focus on safe work practices related to drill rigs, splitting
core and lifting heavy core boxes during the drilling and well installation period, to working around large earth-moving equipment during the construction of a lined pond and tank farm, and finally to
daily operation of the wellfield and tank farm. Maintenance of floating misting systems on the
evaporation pond was a two-person operation and life-vests were required for all personnel working inside the pond fence. The safety issues of consistent concern included:
Heat exhaustion,
Driving safety and potential exhaustion during long employee commutes,
Lightning and strong storm activity during the summer monsoon season,
Rattlesnakes and insects in the field, core shed, and other support buildings, and
Safe work practices by truck delivery drivers while unloading chemical shipments.
7.4 Conclusions and Lessons Learned
Fate transport modeling predicted that the regulated constituents within the wellfield would fall below the relevant AWQS once rinsing achieved sulfate concentrations below 750 mg/L. This was
achieved during the post-leach rinsing phase; the concentrations of trace inorganic metals met the
water quality requirements within two years without use of rinsing amendments such as caustic soda.
The base case timeframe for leaching operations, however, is 5 years with rinsing to be completed during a 2-year period. The BHP field test operated for a total of 101 days of raffinate injection and
an additional 30 days during the injection of intermediate pH, copper-bearing pond water;
reclamation continued with a reduced number of recovery wells an additional year to May 11, 1999.
7.5 Recommendations for New Field Test
Text
A bird fatality occurred during operation, which drew the attention of the agencies. In addition, the
pond was visited by geese, ducks, and pelicans. A bird harassing system should be installed prior to
stating the next test.
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Table 7-1 Post-rinsing water quality results – All wells, 4th Quarter 2000
Parameter
(mg/L unless noted) AWQS
BHP1 BHP2 BHP3 BHP4 BHP5 BHP6 BHP7 BHP8 BHP9 BHP10 BHP11 BHP12 BHP13
4th Qtr 2000
4th Qtr 2000
4th Qtr 2000
4th Qtr 2000
4th Qtr 2000
4th Qtr 2000
4th Qtr 2000
4th Qtr 2000
4th Qtr 2000
4th Qtr 2000
4th Qtr 2000
4th Qtr 2000
4th Qtr 2000
Field EC (umhos/cm) - 1338 838 981 918 873 1517 1326 1448 1398 854 877 974 845
Field pH (units) - 6.51 7.23 6.58 7.12 5.81 4.06 4.06 4.61 3.8 6.78 6.78 6.7 6.68
Aluminum - < 0.025 < 0.025 0.035 0.043 0.4 4.4 4.1 3.5 4.9 0.034 < 0.025 0.085 < 0.025
Antimony 0.006 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001
Arsenic 0.05 0.001 0.001 0.002 < 0.001 0.004 0.008 0.005 0.004 0.009 0.003 0.001 0.003 0.002
Barium 2 0.053 0.056 0.042 0.022 0.0098 0.017 0.02 0.016 0.021 0.01 0.022 0.05 0.031
Beryllium 0.004 < 0.0025
< 0.0025
< 0.0025
< 0.0025 < 0.0025 0.0034 0.0034 0.0034 0.0046
< 0.0025
< 0.0025
< 0.0025
< 0.0025
Cadmium 0.005 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002
Calcium - 140 68 87 85 65 170 130 150 140 65 73 96 67
Chloride - 140 130 130 150 130 140 130 130 140 140 140 150 140
Chromium 0.1 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005
Cobalt - < 0.005 < 0.005 0.013 < 0.005 0.033 0.11 0.11 0.12 0.11 < 0.005 < 0.005 0.023 < 0.005
Copper - 0.8 0.074 1.1 0.43 7.6 24 24 28 26 0.27 0.2 1.7 0.031
Fluoride 4 0.68 0.62 0.94 1.2 1.3 1.7 1.7 1.6 2 1.3 0.5 1.3 0.54
Iron - < 0.05 < 0.05 < 0.05 0.11 < 0.05 0.15 < 0.05 0.17 0.055 0.063 < 0.05 0.14 < 0.05
Lead 0.05 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.002 0.003 0.001 0.002 < 0.001 0.002 0.002 < 0.001
Magnesium - 34 14 18 19 16 39 34 39 36 17 15 24 14
Manganese - 0.170 < 0.003 0.200 0.053 0.510 1.700 1.500 1.600 1.700 0.021 < 0.003 0.330 < 0.003
Mercury 0.002 < 0.0002
< 0.0002
< 0.0002
< 0.0002 < 0.0002
< 0.0002
< 0.0002
< 0.0002
< 0.0002
< 0.0002
< 0.0002
< 0.0002
< 0.0002
Nickel 0.1 0.025 < 0.02 0.022 < 0.02 0.040 0.130 0.140 0.140 0.150 < 0.02 < 0.02 0.031 < 0.02
Nitrate 10 < 1 < 1 0.39 < 0.1 0.38 0.48 0.43 0.47 0.45 0.48 0.38 < 0.1 0.4
Potassium - 6.3 5.6 6 6.1 5.3 6.7 7.3 7.3 7.6 4.8 7.3 5.1 4.8
Selenium 0.05 0.002 0.001 0.001 0.001 0.003 0.002 0.003 0.004 0.003 < 0.001 0.001 0.002 0.001
Sodium - 120 85 84 87 77 81 84 91 75 85 86 75 84
Sulfate - 390 64 130 110 160 570 450 540 490 66 66 160 62
Total Alkalinity - 93 130 100 120 34 < 25 < 25 < 25 < 25 110 130 110 130
Thallium 0.002 - - - - - - - - - - - - -
Zinc - 0.1 < 0.05 < 0.05 < 0.05 0.062 0.22 0.21 0.23 0.24 < 0.05 < 0.05 < 0.05 < 0.05
TDS - 904 493 549 493 524 1140 959 1100 1030 436 446 558 428
TPH - < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5
Adjusted Gross
Alpha (pCi/L) 15 - - - - - - - - - - - - -
Ra-226,228 (pCi/L) 5 - - - - - - - - - - - - -
Uranium - - - - - - - - - - - - -
Source: Brown and Caldwell, 2010. Samples were taken on several dates in the 4th quarter of 2000. Analyses were performed by Nevada Environmental Labs (NEL).
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Table 7-2 Post-rinsing water quality results – All wells, 2nd Quarter 2001
Parameter
(mg/L unless noted) AWQS
BHP1 BHP2 BHP3 BHP4 BHP5 BHP6 BHP7 BHP8 BHP9 BHP10 BHP11 BHP12 BHP13
2nd Qtr 2001
2nd Qtr 2001
2nd Qtr 2001
2nd Qtr 2001
2nd Qtr 2001
2nd Qtr 2001
2nd Qtr 2001
2nd Qtr 2001
2nd Qtr 2001
2nd Qtr 2001
2nd Qtr 2001
2nd Qtr 2001
2nd Qtr 2001
Field EC (umhos/cm) - 1124 815 854 874 762 1171 1008 1150 1066 797 840 900 810
Field pH (units) - 6.34 7.32 7.17 7.14 5.81 3.83 4.14 4.68 3.78 6.86 7.4 6.74 7.55
Aluminum - 0.053 < 0.025 < 0.025 < 0.025 < 0.025 2.5 2.3 2 2.8 < 0.025 < 0.025 < 0.025 < 0.025
Antimony 0.006 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.002
Arsenic 0.05 0.002 < 0.001 < 0.001 < 0.001 0.004 0.009 < 0.001 0.004 0.009 0.003 0.001 0.003 < 0.001
Barium 2 0.043 0.05 0.053 0.017 < 0.0025 0.014 0.02 0.015 0.021 0.009 0.02 0.049 0.03
Beryllium 0.004 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 0.0028 < 0.002 < 0.002 < 0.002 < 0.002
Cadmium 0.005 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002
Calcium - 110 63 68 71 51 110 80 100 90 57 66 78 62
Chloride - 140 130 150 140 130 130 140 130 130 130 120 140 140
Chromium 0.1 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005
Cobalt - 0.007 < 0.005 < 0.005 < 0.005 0.026 0.073 0.071 0.082 0.076 < 0.005 < 0.005 0.016 < 0.005
Copper - 1 0.066 0.14 0.29 5.4 17 14 19 19 0.18 0.11 1 0.021
Fluoride 4 0.78 0.61 0.78 1.1 1.2 1.3 1.3 1.3 1.5 1.2 0.42 1.2 0.44
Iron - < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 0.064 < 0.05 0.09 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05
Lead 0.05 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.002 < 0.001 0.002 < 0.001 < 0.001 < 0.001 < 0.001
Magnesium - 30 13 14 16 14 26 21 27 25 15 14 18 13
Manganese - 0.180 < 0.003 0.011 0.025 0.370 1.100 0.860 1.000 1.100 0.010 < 0.003 0.190 < 0.003
Mercury 0.002 < 0.0002
< 0.0002
< 0.0002
< 0.0002 < 0.0002
< 0.0002
< 0.0002 < 0.0002
< 0.0002
< 0.0002
< 0.0002
< 0.0002
Nickel 0.1 0.027 < 0.02 < 0.02 < 0.02 0.029 0.081 0.084 0.093 0.093 < 0.02 < 0.02 < 0.02 < 0.02
Nitrate 10 0.54 0.35 0.36 < 0.5 0.34 < 0.5 < 0.5 < 0.5 < 0.5 0.44 0.36 < 0.5 < 0.5
Potassium - 5.9 5.3 4.4 5.1 5 6.5 6 6 6.2 4 4.1 4.9 4.4
Selenium 0.05 0.003 0.001 0.001 0.002 0.002 0.002 0.002 0.004 0.002 < 0.001 < 0.001 0.001 < 0.001
Sodium - 100 76 74 76 70 66 62 74 62 74 73 71 79
Sulfate - 240 60 73 93 110 420 280 410 360 59 64 120 52
Total Alkalinity - 80 130 130 120 44 < 25 < 25 < 25 < 25 120 140 120 130
Thallium 0.002 - - - - - - - - - - - - -
Zinc - < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 0.12 0.096 0.14 0.12 < 0.05 < 0.05 < 0.05 < 0.05
TDS - 763 476 488 517 477 892 725 871 785 451 489 523 466
TPH - < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5
Adjusted Gross Alpha (pCi/L) 15 - 57 12.4 12.1 25.7 35.1 14 7.2 10.5 - 19.2 31.7 25.2
Ra-226,228 (pCi/L) 5 0.9 10.5 3 5.1 3.6 5.1 3.8 4 4.8 1.2 2.4 7.6 5.1
Uranium - 7 6 7.2 4.7 1.8 5.4 18.1 5 - 4.4 10.9 3.1
Source: Brown and Caldwell, 2010
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Table 7-3 Post-rinsing water quality results – All wells, 4th Quarter 2003
Parameter
(mg/L unless noted) AWQS
BHP1 BHP2 BHP3 BHP4 BHP5 BHP6 BHP7 BHP8 BHP9 BHP10 BHP11 BHP12 BHP13
4th Qtr 2003
4th Qtr 2003
4th Qtr 2003
4th Qtr 2003
4th Qtr 2003
4th Qtr 2003
4th Qtr 2003
4th Qtr 2003
4th Qtr 2003
4th Qtr 2003
4th Qtr 2003
4th Qtr 2003
4th Qtr 2003
Field EC (umhos/cm) - 808 822 798 853 687 728 636 756 701 727 838 786 761
Field pH (units) - 6.12 7.74 7.37 6.96 6.46 3.96 5.14 4.48 4.34 6.96 7.57 7.3 7.51
Aluminum - < 0.1 < 0.1 < 0.1 < 0.1 < 0.1 0.96 0.49 0.91 1.1 < 0.1 < 0.1 < 0.1 < 0.1
Antimony 0.006 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001
Arsenic 0.05 0.002 0.002 0.002 0.002 0.005 0.010 0.009 0.004 0.006 0.004 0.002 0.002 0.002
Barium 2 0.029 0.039 0.05 0.017 0.0081 0.011 0.023 0.013 0.014 0.011 0.017 0.052 0.025
Beryllium 0.004 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.0011 < 0.001 0.0011 0.0011 < 0.001 < 0.001 < 0.001 < 0.001
Cadmium 0.005 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001
Calcium - 64 61 62 72 44 51 34 48 46 53 67 69 62
Chloride - 150 140 140 140 140 140 140 140 140 130 150 150 140
Chromium 0.1 < 0.001 0.002 0.001 0.001 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.001 0.001 0.001 0.001
Cobalt - 0.007 0.005 < 0.001 < 0.001 0.012 0.031 0.021 0.037 0.032 < 0.001 < 0.001 0.002 < 0.001
Copper - 1.4 0.04 0.081 0.22 2 8.5 3.4 9.6 8.9 0.14 0.048 0.2 0.017
Fluoride 4 0.91 0.69 0.55 0.88 1.7 0.86 0.94 0.92 0.96 1 < 0.4 0.84 < 0.4
Iron - < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05
Lead 0.05 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.004 0.001 0.004 0.004 < 0.001 < 0.001 < 0.001 < 0.001
Magnesium - 18 13 13 16 12 12 9 13 12 14 13 16 13
Manganese - 0.170 0.007 0.004 0.014 0.180 0.450 0.260 0.460 0.470 0.007 < 0.003 0.029 < 0.003
Mercury 0.002 < 0.0002
< 0.0002
< 0.0002
< 0.0002 < 0.0002
< 0.0002
< 0.0002
< 0.0002
< 0.0002
< 0.0002
< 0.0002
< 0.0002
< 0.0002
Nickel 0.1 0.025 0.004 0.003 0.006 0.016 0.036 0.026 0.042 0.041 0.006 0.002 0.008 0.003
Nitrate 10 0.94 0.65 0.47 0.45 0.49 0.53 0.49 0.52 0.5 0.41 0.37 0.45 0.48
Potassium - 6.4 7.4 7.1 7.6 6.2 5.8 5.5 6.2 5.7 6 6.5 5.8 6.3
Selenium 0.05 < 0.001 < 0.001 < 0.001 0.001 < 0.001 0.002 0.002 0.003 0.001 < 0.001 < 0.001 < 0.001 < 0.001
Sodium - 81 92 89 94 85 75 82 82 78 89 93 91 90
Sulfate - 130 67 69 130 67 150 97 160 130 60 97 76 57
Total Alkalinity - 64 140 150 130 84 < 6 10 < 6 < 6 130 130 130 150
Thallium 0.002 - - - - - - - - - - - - -
Zinc - < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 0.052 < 0.05 0.067 0.073 < 0.05 < 0.05 < 0.05 < 0.05
TDS - 500 470 470 550 420 550 440 530 490 440 520 500 480
TPH - < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25
Adjusted Gross Alpha (pCi/L) 15 - - - 8.5 - - - - - - 10.3 14.8 11.5
Ra-226,228 (pCi/L) 5 1.2 - 0.4 2.4 2.2 2.6 1 2.3 2.4 0.6 4.8 6.4 4.4
Uranium - - - - 7.5 - - - - - - 5.7 14.2 6
Source: Brown and Caldwell, 2010. Samples were taken on several dates in the 4th quarter of 2003. Analyses were performed by Aerotech Environmental Labs and Radiation Safety Lab.
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Table 7-4 Post-rinsing water quality results – All wells, 4th Quarter 2004
Parameter
(mg/L unless noted) AWQS
BHP1 BHP2 BHP3 BHP4 BHP5 BHP6 BHP7 BHP8 BHP9 BHP10 BHP11 BHP12 BHP13
4th Qtr 2004
4th Qtr 2004
4th Qtr 2004
4th Qtr 2004
4th Qtr 2004
4th Qtr 2004
4th Qtr 2004
4th Qtr 2004
4th Qtr 2004
4th Qtr 2004
4th Qtr 2004
4th Qtr 2004
4th Qtr 2004
Field EC (umhos/cm) - 813 786 810 982 714 757 663 769 709 736 849 805 782
Field pH (units) - 6.08 7.91 7.65 7.1 6.46 3.92 5.43 4.8 4.45 7.11 7.88 7.51 8.14
Aluminum - - - - < 0.2 - - - - - - - - -
Antimony 0.006 - - - < 0.001 - - - - - - - - -
Arsenic 0.05 - - - 0.002 - - - - - - - - -
Barium 2 - - - 0.019 - - - - - - - - -
Beryllium 0.004 - - - < 0.001 - - - - - - - - -
Cadmium 0.005 - - - < 0.001 - - - - - - - - -
Calcium - - - - 89 - - - - - - - - -
Chloride - - - - 120 - - - - - - - - -
Chromium 0.1 - - - < 0.001 - - - - - - - - -
Cobalt - - - - 0.004 - - - - - - - - -
Copper - - - - 0.22 - - - - - - - - -
Fluoride 4 - - - 1.1 - - - - - - - - -
Iron - - - - < 0.05 - - - - - - - - -
Lead 0.05 - - - < 0.001 - - - - - - - - -
Magnesium - - - - 20 - - - - - - - - -
Manganese - - - - 0.014 - - - - - - - - -
Mercury 0.002 - - - < 0.0002 - - - - - - - - -
Nickel 0.1 - - - 0.007 - - - - - - - - -
Nitrate 10 - - - 0.66 - - - - - - - - -
Potassium - - - - 8.6 - - - - - - - - -
Selenium 0.05 - - - < 0.001 - - - - - - - - -
Sodium - - - - 110 - - - - - - - - -
Sulfate - 110 58 66 180 68 130 85 150 110 55 95 70 51
Total Alkalinity - - - - 110 - - - - - - - - -
Thallium 0.002 - - - - - - - - - - - - -
Zinc - - - - < 0.05 - - - - - - - - -
TDS - - - - 710 - - - - - - - - -
TPH - - - - - - - - - - - - - -
Adjusted Gross Alpha (pCi/L) 15 - 28 - - - - - - - - - - -
Ra-226,228 (pCi/L) 5 - 8.5 - 3.6 - - - - - - - - -
Uranium - - 8.6 - - - - - - - - - - -
Source: Brown and Caldwell, 2010. Samples were taken on several dates in the 4th quarter of 2004. Analyses were performed by Aerotech Environmental Labs and Radiation Safety Lab.
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Table 7-5 Post-rinsing water quality data – All wells, 2nd Quarter 2007
Parameter
(mg/L unless noted) AWQS
BHP1 BHP2 BHP3 BHP4 BHP5 BHP6 BHP7 BHP8 BHP9 BHP10 BHP11 BHP12 BHP13
2nd Qtr 2007
2nd Qtr 2007
2nd Qtr 2007
2nd Qtr 2007
2nd Qtr 2007
2nd Qtr 2007
2nd Qtr 2007
2nd Qtr 2007
2nd Qtr 2007
2nd Qtr 2007
2nd Qtr 2007
2nd Qtr 2007
2nd Qtr 2007
Field EC
(umhos/cm) - 916 809 805 1117 783 836 677 859 737 765 890 864 806
Field pH (units) - 6.02 7.34 7.33 6.58 6.05 4.35 5.11 4.65 4.58 6.72 7.12 6.79 7.46
Aluminum - < 0.2 < 0.2 0.2 < 0.2 < 0.2 1 0.47 1.2 1 < 0.2 < 0.2 < 0.2 < 0.2
Antimony 0.006 0.003 < 0.003 0.003 < 0.003 < 0.003 < 0.003 < 0.003 < 0.003 < 0.003 < 0.003 < 0.003 < 0.003 < 0.003
Arsenic 0.05 0.002 0.002 0.002 0.002 0.005 0.011 0.013 0.007 0.011 0.004 0.002 0.002 0.002
Barium 2 0.034 0.043 0.055 0.027 0.0071 0.015 0.026 0.017 0.015 0.0079 0.019 0.048 0.029
Beryllium 0.004 < 0.001 < 0.001 0.001 < 0.001 < 0.001 0.001 < 0.001 0.0011 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001
Cadmium 0.005 < 0.001 < 0.001 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001
Calcium - 76 63 66 110 53 54 35 54 41 55 75 75 66
Chloride - 90 130 150 130 140 130 140 130 140 140 140 140 140
Chromium 0.1 < 0.001 0.002 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.001 0.001 0.002 0.002
Cobalt - 0.007 < 0.001 0.001 0.002 0.014 0.035 0.024 0.043 0.028 0.001 0.002 0.002 0.001
Copper - 1.4 0.074 0.087 0.67 2.7 10 3.5 12 8.7 0.15 0.066 0.33 0.017
Fluoride 4 0.98 0.68 0.88 0.95 1.2 0.97 0.86 1.2 1.1 1.2 0.61 0.86 0.53
Iron - 0.056 < 0.05 0.05 < 0.05 < 0.05 0.32 < 0.05 0.27 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05
Lead 0.05 < 0.001 < 0.001 0.001 < 0.001 < 0.001 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001
Magnesium - 21 14 15 24 15 13 10 15 12 15 15 18 14
Manganese - 0.230 < 0.003 0.020 0.043 0.240 0.480 0.270 0.530 0.420 0.006 0.003 0.025 < 0.003
Mercury 0.002 < 0.0002 < 0.0002 0.0002
< 0.0002 < 0.0002
< 0.0002
< 0.0002 < 0.0002
< 0.0002 < 0.0002
< 0.0002 < 0.0002
< 0.0002
Nickel 0.1 0.032 0.003 0.003 0.015 0.020 0.039 0.026 0.050 0.038 0.008 0.004 0.013 0.003
Nitrate 10 0.93 0.63 0.68 0.68 0.72 0.72 0.77 0.76 0.69 0.66 0.61 0.79 0.7
Potassium - 5.2 5.4 6.9 6.9 5.7 5.2 4.7 5.4 5.3 4.8 5.6 5.2 5.2
Selenium 0.05 0.002 < 0.002 0.002 0.002 0.003 0.002 0.002 0.005 0.003 < 0.002 < 0.002 0.002 < 0.002
Sodium - 88 94 100 110 93 86 88 95 86 92 100 93 95
Sulfate - 160 56 62 250 100 170 81 190 140 52 100 96 50
Total Alkalinity - 58 130 120 95 55 < 6 9 < 6 < 6 110 120 120 140
Thallium 0.002 - - - - - - - - - - - - -
Zinc - < 0.05 < 0.05 0.05 < 0.05 < 0.05 0.058 < 0.05 0.051 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05
TDS - 600 500 490 770 500 600 470 640 530 450 550 540 480
TPH - - - - - - - - - - - - - -
Adjusted Gross
Alpha (pCi/L) 15 - 11.9 8.9 - - - - - - - - 5 3.8
Ra-226,228 (pCi/L) 5 < 0.4 8.9 5.6 3.3 1.4 3.6 < 0.3 2.2 1.6 < 0.4 3.6 6 3.9
Uranium - - 7.7 9.6 - - - - - - - - 14.6 6
Source: Brown and Caldwell, 2010. Samples were taken on several dates in the 2nd quarter of 2007. Analyses were performed by Aerotech Environmental Labs and Radiation Safety Lab.
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Appendices
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Appendix A: Wellfield Extraction Graphs
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Appendix B: Water Quality Graphs
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