Understanding The Nature Of The Mineral Scale Problems in Ghawar Gas Condensate Wells To Describe And Apply The Right Approach Of Mitigation.
C. A. Franco Saudi Aramco
East Administration Building
Udhailiyah, 31311
H.M Al-Marri, M.A. Al-Asiri, H.M. Al-Hussain
Saudi Aramco
East Administration Building
Udhailiyah, 31311
ABSTRACT
Different mechanisms are contributing to mineral scale generation in the gas condensate producer wells in Ghawar Field. Carbonate scales are the main mineral scale growing up in the reservoir side while sulfate scales are the mineral compounds deposit along the production strings.
Several methods have been implemented to dissolve the mineral scales in the reservoir and to mitigate the mineral deposits found into production string. A combination of mechanical tools (Vibra hammer, motor-mills, Pulsonix and variety of scale blasters) with chemical fluids (foam, DTPA, water and low HCl concentration) have been the main methods used to clean the deposits into tubing string. Currently, a scale strategy to mitigate the future impact of mineral scales in the reservoir, as consequence of reservoir pressure decline, is being development.
This paper summarizes the scale phenomena in Ghawar gas condensate field, the mineral scale distribution in the total production system, the techniques involved to control their growing, the current scale map distribution, the techniques used to scale identification and stabilization (scale index) and the future program that require to be implemented in order to minimize scale impact on production and well interventions.
Paper No.
8347
Copyright
?2008 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole must be in writing to NACE
International, Copyright Division, 1440 South creek Drive, Houston, Texas 777084. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association. Printed in the U.S.A.
INTRODUCTION
Brief Description of Khuff Reservoir
A global mineral scale mitigation strategy is being designed for the entire non-associated reservoirs currently producing from Ghawar field. Initially, a pilot mineral scale project will be implemented in the HARADH wells connected to Hawiyah Gas Plant (HWGP) which are producing from Khuff-
B &
C carbonate reservoirs. Actually, there are 44 HARADH wells connected to HWGP and the average production of this group of wells is 600 MMscfd, 64400 SBbls of condensate with an average WGR of 2.0 MMscf/SBbl.
The Khuff rich gas condensate reservoir is produced from carbonate formations in the late Permian age which underline the Arab D oil bearing zone in the Ghawar field. This field is located in the eastern province of the Kingdom of Saudi Arabia.
The table 1 shows a typical PVT composition from reservoir samples taken in a well producing from both reservoirs (Khuff B & Khuff C).
During the early stages of development the wells were drilled as vertical wells and completed as cased hole with 4-1/2" OD and/or 7" OD carbon steel production string. Since early 2003 a strong strategy to drill open hole horizontal multilateral wells was implemented, the lateral lengths can vary from 2500' to >5000 ft depending on reservoir quality and drilling accessibility. Non-retrievable packers or polished bore receptacles (PBR) are implemented as the isolating tubing/casing annulus assembly.
The vertical wells are initially perforated in the prospective intervals and immediately stimulated by performing massive acid frac jobs, these stimulation jobs involve the injection at high pressure and rates of large HCl volume (generally 15 and 28 %/wt as acid concentration and split in stages separates by linear and x-linked gels). Stimulation jobs have been not yet performed in horizontal multilaterals wells although the implementation of a successful stimulation technique will be required in the future.
Description of Mineral Scale Problem
Mineral scales deposits have been detected in the entire production system since the early production stages. The reservoir has been continuously depleted since 1984 generating a significant productivity decline. As long as the pressure decline takes place a significant amount of mineral scales reach the supersaturated conditions generating deposits in the entire production system. The reservoir conditions (HPHT), the induced solids during drilling operations, the type of reservoir water, the carbon-steel composition of production string and the presence of sour gas are the main sources generating a multi-component mineral scale deposits in all parts of entire production system. This study is focused on the main parts of upstream system: wellbore area and production string.
Mineral Scale Scenario in the Production String
The scales occurring in the production string appear to be mainly due to corrosion related issues, many types of scales are being found in the production string being the sulphide scales those with major occurrence. Among the other important mineral compounds, iron oxides, iron hydroxides, calcium carbonate and barium sulphate are also frequently found together with iron sulphide scales. The occurrence of iron sulfide scales in Ghawar field has been broadly explained in the literature 1,2, 3 and constitute a high source of production string plugging.
Several problems are associated with the accumulation of mineral scales in the production string: reduction in well productivity, well accessibility loss, and increasing in the costs of work-over or coiled tubing (CT) interventions. Currently, coil tubing operations are being performed to remove the minerals scales in Ghawar field; the CT intervention combines mechanical tools (vibra hammer, scale blaster and fluidic oscillation tools) with foams to supply a suitable removal system4,5. Although the coil tubing operations have been performed with high grade of success there are many important factors (environment, coil tubing stuck, deferred production due to long time operation and costs) which are indicating the requirement to look for alternatives to avoid facing with this no desirable productivity problem.
The table 2 shows the characterization of four solid samples recovered in same number of HARADH wells flowing to HWGP. The table confirm the multi-variety of mineral scales found in the production string, the table is also confirming the high presence of sulfate scales combined with iron and carbonate scales.
Mineral Scales Depositing in Wellbore Area
The mineral scale formation in the wellbore area has been suspected as consequence of abnormal reduction productivity observed in some wells in which mineral scale deposits in production has been not detected (confirming when calliper logs are run in the wells) or their current amount is not enough to generate sensible changes in well productivity.
There are not available studies that can explain the current mineral scale scenario currently taking place in the wellbore area. It is suspected that an important scale environment is being formed as consequence of two main problems: reduced near wellbore pressure and/or increasing of scaled potential because the evaporation of water into the gas phase.
The consequences of scale deposition in carbonate reservoir has been very well explained6, in summary, the mineral scale compounds restricted the flow in the fracture system (natural or induced) by several ways, depositing like a film in large fractures or depositing and migrating in smaller fractures.
The current campaign related to mineral scale mitigation in Ghawar field has been focused in to remove mineral scales deposited inside the production string. As was outlined before, this campaign is based on removal techniques in which CT operations (involving the combination
of mechanical tools and foams) are performed to cleanout the well. Because there are not guidelines or procedures focused on inhibition techniques that can be applied in production string and/or in the reservoir, and the mineral scale problems in the wellbore area has been not addressed, it is necessary to develop a methodology dedicated to understand the problem in the reservoir and to optimize the current strategy in the production string.
This paper describes the first engineering methodology attempted to investigate how the mineral scales are affecting the wellbore area: type of scales, amount deposited, and the impact on well productivity.
The paper also includes a methodology to calculate the well productivity impact occurring in the production system when mineral scales are deposited inside the production string. Finally, and based on previous analysis, the first attempt to outline the most probable mineral scale strategy for gas producer wells in Ghawar field will be presented. This study is focused on the HARADH wells currently flowing to Hawiyah Gas Plant (HWGP) which were chosen to perform the pilot field tests. Experience and lesson learnt in these wells will be applied to extend the future strategy to all gas-condensate wells producing from Ghawar field.
ENGINEERING STUDY TO INVESTIGATE THE MINERAL SCALE IMPACT ON KHUFF
RESERVOIR
The engineering study dedicated to wellbore area covered the following stages:
Analysis of Water Geochemical Data
?Geochemical reservoir water data was collected for all HARADH wells flowing to HWGP.
?The data was analyzed for mineral scales by running Prediction software.
o The scale tendency was calculate in a range of pressure of 2000 to 8500 Psia and at fixed reservoir temperature of 260 oF. A clear idea about the type of scales
and their tendency to be depositing at wellbore area were reached at this point of
analysis. The first list of prioritised wells was built up based on scale tendency
parameter.
o The mineral scale potential mass was calculated and a second list of prioritised wells was also built up.
?Combine productivity data with previous calculated rate deposition to estimate the total amount of scales really deposited in the wellbore area. A final list of prioritised wells was obtained.
The final list of prioritised wells showed that 80% of the current gas-condensate wells are facing with mineral scale deposits at wellbore area. Currently, calcite and celestite constitute the main mineral scales being deposited at wellbore area but, the presence of strontianite, anhydrite, magnesite, barite and brucite are also simulated due mainly to the high reservoir pressure depletion expected in the field.
Calculate the Impact of Mineral Scale on Well Productivity.
The potential mass calculate in previous section is now used to perform well productivity analysis. The well H-1, who constitutes one of the well identified in the final list of prioritised wells, was chosen to perform the well productivity analysis. The general procedure followed in this analysis was the following:
? A simulation analysis was performed to calculate gas rate production. Real gas rate production vs. modelled gas rate production were compared and skin damage evolution was verified.
?The permeability reduction due to mineral scale presence in the wellbore area was calculated.
?Several prediction runs were performed to simulate the gas rate performance under following options:
o Base Case: The forecast production assuming that nothing is performed in the well and the current reduced permeability is kept.
o P10 Case: This case assumed that a stimulation job was performed on the well to restore the original permeability. An inhibition job was also performed to
avoid mineral scale precipitation at wellbore area it is also assumed that not
damaged is induced during the injection of inhibitor in the reservoir.
o P50 Case: This cased is similar to P10 case but assume that some damage is induced in the reservoir during the injection of inhibitor. In this case is also
assumed that the induced damage is being removed as long as the well is
producing.
o P90 Case: This case assumes only stimulation to remove the mineral scale damage and restore the original permeability but does not include inhibition job.
The final results showed the high benefit that an inhibition strategy can provide in terms of additional gas reserves to be produced. The obtained results (assuming two years as inhibition lifetime and that the job is performed in November-2007) showed that the additional gas produced reserves for P10, P50 and P90 cases were 7.1 bcf, 6.6 bcf, and 4.0 bcf respectively. The results are confirming the high benefits that a scale strategy can provide, under the reservoir point of view, if this includes a combine technology focused on stimulation and inhibition.
Calculate Well Productivity Impact due to Mineral Scales Deposited inside the Production String.
The mineral scales deposited in the tubing string have been broadly studied since the early production stages. The iron sulphide scales constitute the main source of deposits in those wells with severe corrosion problems and presence of sour gas. A combination of carbonate, iron and sulphate scales have been also found as the main deposited downhole scales in wells with low corrosion process and presence of sweet gas.
The calculated amount of scales currently deposited, the types of scales and their impact on well productivity were the main objectives worked in this study. The future de-scaling strategy is now being addressed to switch from mechanical options to chemical fluids; the general idea is to implement new technology in which fluids based on DTPA or EDTA can be injected and scales can be efficiently removed. The amount of scales is required to design the volumes of required chemicals, the types of scales is also required to define the type of chemicals to be
used, and the well productivity impact is required to determine the benefits of the chemical de-scaling jobs in terms of additional gas production.
The general procedure performed in this stage was the following:
?The simulation model was run and the production profile vs. time (gas rate, reservoir pressure, GOR, etc).
? A nodal system analysis was performed on 1 year time steps in order to calculate the average pressure and temperature profiles in the production string.
?The corrosion model was run for every time step, the corrosion rate and the corresponding cumulative wall loses were calculated. This step verifies if corrosion is really an issue and iron is being released from the production string (which is essentially carbon steel)
?The Prediction software was run in each one of time steps using the previous pressure-temperature profile in the production string. The water samples were contaminated with iron in order to model the iron presence for those wells in which corrosion process is taking place. Lab analysis performed on water samples (taken on wells with low to severe corrosion) indicated that iron concentration can vary from 30 to 370 ppm. We used 100 ppm as average level of iron contamination. This analysis reported the cumulative amount and the types of scales already deposited inside the production string.
? A nodal system analysis was again run in order to calculate the real effect of cumulative amount of scale already deposited inside production string on well productivity. To do that, a solution node was located at bottom hole conditions and a sensibility analysis performed by reducing the effective ID pipe according to amount of scale deposited in each one of time steps.
?For each time step a graphs of VLP vs. IPR was built up and the gas rate calculated.
?Several prediction runs were performed to simulate the gas rate performance under following options:
o Base Case: The forecast production assuming that nothing is performed in the well, de-scaling and/or stimulation jobs were not performed on the well.
o P10 Case: This case assumed that a stimulation job as well as de-scaling job were performed on the well to restore original permeability and remove scale
deposited inside production string. An inhibition job was also performed to avoid
mineral scale precipitation at wellbore area and inside production string, it is also
assumed that not damaged is induced during the injection of inhibitors in the
production system
o P50 Case: This cased is similar to P10 case but assume that some damage is induced in the reservoir during the injection of inhibitor. In this case is also
assumed that the induced damage is being removed as long as the well is
producing.
o P90 Case: This case assumes stimulation and de-scaling jobs but not inhibition.
This paper describes the previous procedure by applying it on the well H-39. MIT logs taken on November-2007 in this well revealed that approximately 15000 lbs of mineral scales are currently deposited inside the production string, the logs also revealed that the accumulation is distributed along the production string in the last 5626 ft of pipe section.
Once the previous analysis was performed through all described stages the following results were found:
?It was confirmed that corrosion process is taking place inside the production string, the cumulative wall lost is ranging from 3 to 13% along the 4-1/2 production tubing (top to bottom) and 5% along the 7" OD production liner.
?The scale analysis showed that the main minerals being deposited in the string are iron sulphide, ferric hydroxide and calcium carbonate.
?The effective cumulative ID reduction reached until the moment in the scaled section is
14.75%.
?The current gas production rate is being reduced in 2.3 MMscfd due to scale accumulation inside the production string.
?The additional gas produced reserves were 2.2 bcf, 2.1 bcf and 1.3 bcf for P10, P50 and P90 cases respectively (it was assumed 1 year as lifetime for combined inhibitor jobs (scale/corrosion).
Developing the Engineering Study for Wellbore Area
Water Data
The table 3 shows the geochemical analysis performed on 39 water samples available from HRDH wells flowing to HWGP. The average ion concentration of reservoir water is summarized in the table 4 and figure 1. The water is clearly identified as sodium-chloride type in which important amount of calcium and magnesium are also detected.
The water geochemical analysis described in table 3 was complemented with density, pH and gases content to fulfil the data required to run prediction software. For those wells in which measurements of gas content were not available the PVT data was used and the gas concentration calculated by using the following formulas:
[Gas]w = 3.74*Rsw*γg*P*M*W/ [Z*(T+460)* γw] (1)
Where
?[Gas]w : Gas concentration in water at P,T conditions, ppm
?Rsw : Solution gas/water ratio of formation water, scf/sbbl
?P : Pressure, Psia
?T : Temperature, oF
?M : Gas mole percent (CO2, H2S or C1), %/mol
?W : Gas atomic weight gr/mol
?Z : Gas compressibility factor
?γg : Gas specific gravity (air =1)
?γw : Brine specific gravity
The Rsw was calculated by using the McCain correlation7.
Determining the type of Scales Depositing in Wellbore Area
Each one of the water samples were analyzed by running prediction software. The pressure was varied from 8500 to 2000 Psia to cover all the reservoir pressure ranges modelled in material balance calculations, the temperature value was fixed at 260 oF which is the average value for Khuff reservoir.
The process followed through the prediction software was the following:
The Scale tendency for more than 40 possible solid precipitates was calculated for each one of the samples in the range of pressure and temperature previously described. The scale tendency is our first comparative mineral scale parameter checked in the process to build up the list of prioritised wells.
?Seven type of scales displayed low to high probability to be depositing at wellbore area conditions, these scales are: CaCO3, BaSO4, SrSO4, SrCO3, CaSO4, MgCO3, and MG(OH)2.
?Calcium carbonate is the main scale being formed at the wellbore area with the following average performance:
o77.5% of the samples exhibit a calcite ST>1.0 (brine supersaturated with calcite). The figure 2 shows the average scale index calculated for all HRDH
wells. The well H11 shows the maximum level of precipitation. The figure 3
shows the ST performance in function of pressure for the top ten wells with
major probability of calcite deposition at wellbore area, the wells H-10, H-1,
H-4, H-21, H-6, H-11, H-32, H-18, H-17 and H-35 constitute those in with a
high scale tendency was found. The figure 4 shows the same graph but
related to the wells with less probability to deposit scale (in terms of scale
tendency). The previous two figures show that calcite is the main mineral
scales currently being deposited in the wellbore area and its occurrence is
increasing by the continuous reservoir pressure depletion.
o22.5 % of the samples exhibit a calcite ST>0 but <1 (brine undersaturated with calcite). The low tendency observed in these wells is probably due to
the combination of two factors:
Low ph, indicating that the samples were probably taken after short time following an acid job.
Water corresponds to evaporated water instead of reservoir water.
This is the typical performance monitored in low WGR wells.
?Strontium Carbonate or strontianite is the second mineral scale in importance, the average performance detected was the following:
o35 % of the samples displayed a ST>1 indicating supersaturated conditions related to deposition of strontianite. This performance is indicating that
strontianite has a significant importance related to mineral scale deposits at
wellbore area. The figure 5 shows the average strontianite ST calculated for
the HRDH wells flowing to HWGP. High supersaturated conditions were
found in the following wells: H6, H-10, H-1, H-4, H-32, H-18, H-17, H-13, H-
25, H-11.
o The rest of the wells are displaying a ST<1 with low likely of deposition.
o The ST performance in function of reservoir depletion is showed in the figure
6 for those wells under supersaturated conditions. As similar for calcite, the
strontianite precipitation is also increasing as long as reservoir pressure is
decreasing.
?Barium sulphate or barite is the third mineral scale in importance, the average performance detected was the following:
o92.5% of the samples displayed a ST>0 but less than 1. This performance is indicating that barite is not a major problem at wellbore area conditions. The
figure 7 shows the average barite ST calculated for the HRDH wells flowing
to HWGP, only the wells H-29, H-6 and H-14 display some probability to
deposit barite at wellbore area conditions.
o The ST performance in function of reservoir depletion is showed in the figure
8 for those wells under supersaturated conditions. As similar for calcite and
strontianite, the barium sulphate precipitation is also increasing as long as
reservoir pressure is decreasing.
?Strontium sulphate or celestite is the fourth mineral scale in importance, the average performance detected was the following:
o92.5% of the samples displayed a ST>0 but less than 1. This performance is indicating that celestite is not a major problem at wellbore area conditions.
The figure 9 shows the average barite ST calculated for the HRDH wells
flowing to HWGP, only the wells H-1, H-29 and H-17 display some probability
to deposit celestite at wellbore area conditions.
o The ST performance in function of reservoir depletion is showed in the figure
10 for those wells under supersaturated conditions. As similar for calcite,
strontianite and barite, the celestite precipitation is also increasing as long as
reservoir pressure is decreasing.
?The rest of the scales with likely to be deposited in the wellbore area are CaSO4 (anhydrite), MgCO3 (magnesite), and Mg(OH)2 (brucite). This scales displayed the following performance.
o Anhydrite: undersaturated conditions were calculated for all the samples.
There is not likely of deposition for this type of scale at wellbore area.
o Magnesite: similar performance like anhydrite was observed for this scale.
There is not likely of deposition for this type of scale at wellbore area.
o Brucite: There is a very low probability to deposit brucite in the well H-616, the rest of the wells have not deposition problems regarding this scale.
o The figure 11 shows the magnitude of scale index calculated in each one of the wells for previous mineral scales. The figure 12 summarizes the scale
tendency performance against reservoir pressure for these same scales.
The same performance as per previous scales was also detected for
anhydrite, magnesite and brucite, its say, scale tendency increasing when
reservoir pressure is decreasing.
?The figure 13 is the first attempt performed building up the list of prioritised wells.
This starting point summarizes the wells in risk of scale deposition in the wellbore area based on those well displaying mineral scale tendency grater than 1. It is clear that calcite has the most important effect on wellbore area when compared with the other scales detected; this carbonate compound constitutes the main mineral scale deposit to be considered in any future stimulation and inhibition job.
There are 31 wells with high likely of calcite deposition in the wellbore area, 14 wells with strontianite, 3 with celestite, 1 with magnesite, and 1 with anhydrite.
?The figure 14 summarizes the list of prioritised wells based on the number of scales likely being formed in the wellbore area. The wells H-1, H-11 and H17 correspond to the wells with major number of detected mineral scales.
The potential mass of scale deposited was calculated after the scale tendencies were obtained. This potential mass constitutes our second mineral scale parameter in the process to build up the list of prioritised wells. This important parameter is key to calculate the amount of mineral scales being deposited in the wellbore area. The performance of this parameter for each one the previous detected minerals scales was the following:
?The values of potential mass confirmed that calcium carbonate is essentially the mineral scale really deposited in the wellbore area.
o The figure 15 shows the average potential mass of calcite. The figure shows that calcite is being deposited in all the wells in which a scale tendency value
grater than 1 was previously obtained. The wells H-10, H-1, H-21, H-18, H-
32, H-17, H-11, H-6, H-7, and H-13 comprehend the top ten wells displaying
the major potential mass regarding calcite scale.
o The figure 16 shows how the potential mass is changing with reservoir depletion. The graph confirms that the amount of calcite will be increasing as
long as the reservoir is being depleted.
?Although 14 wells were identified with high likely to deposit strontianite no potential mass was calculated for this wells. This performance is indicating that all available carbonate was spent during the calcite generation.
?The three wells identified with likely to deposit celestite in the wellbore were confirmed by the potential mass parameter. The figure 17 shows the celestite performance against reservoir pressure. Wellbore area restriction by celestite deposition is currently taking place and increasing with time in the wells H-1, H-29 and H-17.
?No potential mass was also observed for barite, anhydrite, magnesite and brucite.
The list of prioritized wells has been reduced in terms of scales really being deposited in the wellbore area. The calcite is regulating the formation of carbonates scales while strontium is regulating the formation of sulfate scales. Calcite and celestite are the unique scales being deposited in the wellbore area. The figure 18 shows the list of prioritized wells based on mineral scale potential mass while the figure
19 shows the final number of mineral scales being really deposited in each one of the
scaled wells. The wells H-1 and H-17 appear to be the most affected wells by mineral scale depositions at the wellbore area.
The average cumulative amount of scales really being deposited in the wellbore area can now be calculated by using the following equation:
Ms = 3.50527*10-4*Qs* γw*Qw*t p (2)
Where:
Ms : Mass of scale being deposited, lbs
Qs : Mineral scale rate deposition, mg/lt
Qw : Water production rate, BWPD
t p : Effective production elapsed time, days
The table 5 shows the productivity data required to resolve the equation (2) for the wells with detected scale problems in the wellbore area. The figure 20 shows the average cumulative amount of calcite deposited at the wellbore area until November-2007, the figure 21 shows the same graph for celestite and figure 22 shows the list of prioritised wells taking into account the total amount of scales deposited in the wellbore area (calcite plus celestite).
The previous analysis showed that 80% of the current HRDH wells flowing to HWGP present problems with minerals scale deposits at the wellbore area. The mineral calcite constitutes the main solid material being deposited in the majority of the wells followed by celestite which is being deposited in 3 wells. Although the potential mass for other mineral scales that exhibited a positive scale tendency in the scale study was zero, special attention should be kept on them because the continuous pressure drop currently observed in Khuff reservoir. The analysis also gave us the list of candidate wells in which the future scale inhibition strategy could be focused as at starting point. The wells H-10, H-31, H-21, H-32, H-11, H-18, H-38, H-25, H-7, H-17, H-22, and H-1 constitute an excellent set of candidate wells to perform any type of field pilot related to mineral scale mitigation at wellbore area.
Calculating the Impact of Mineral Scale Deposits on Well Productivity
The calculus of the real effect that mineral scale deposits are exerting on the well productivity is showed by following the process initially described. The well H-1 is used to explain the process step by step.
Simulation Model
MBAL and PROSPER softwares were combined to generate the reservoir model for the well H-1. Once the history match was obtained by adjusting the required reservoir parameter a set of several runs were performed.
The figure 23 shows the prediction run in which the gas rate production calculated by the model (blue line) is compared with the real gas rate production monitored in the well during its production life (red line). The rates calculated by the model do not assume any kind of skin evolution during the production life, only reflex the production response based on the reservoir pressure depletion. The real performance reflex the gas rate being affected by the additional pressure drops generated by skin damage evolution in the reservoir and mineral accumulation in the production string.
The cumulative amount of gas production lost due to additional pressure drops generated in the production system is calculated as 11.3 bcf at the end of the production prediction period (November-2007). Although accumulation of mineral scales have been calculated at the wellbore area in this well, it is true that there are other factor also contributing to the skin damage evolution (condensate banking, permeability changes, production from offset wells, etc) which will not be covered in this study.
The effect of mineral scale on skin damage evolution is calculated based on permeability reduction concept. We are assuming that the amount of scale that is currently depositing at the wellbore area is being homogeneously depositing around the net interval open to flow. Using this concept we can calculate the damaged radius covered by the mineral deposits and also the percentage of permeability reduction in the affected wellbore area. To do that we used the Hawkins' equation8, this defines a skin factor in terms of the properties of the equivalent altered zone as:
S = (k/k s -1)ln(r s/r w) (3)
Where:
S : skin damage factor
k : original permeability
k s : altered permeability
r s : altered zone radius
r w : well radius
By applying the equation (3) a cumulative reduction of 11.3% and a total altered zone radius of 8.2 inches were calculated for the well H-1 (see green and yellow lines in figure 23).
The previous data reveals important parameter that should be taking into account when designing stimulation and inhibition jobs. The minimum volume of acid required to stimulate the well should cover an equivalent pore volume of 8.2 inches of radius in the entire effective length open to flow.
Restoring Permeability and Arresting Gas Rate Decline by Implementing Stimulation and Inhibition Jobs.
The stimulation jobs performed on HRDH wells have displayed and excellent performance regarding the increasing got in the initial gas rate but is also true that this additional rate can be quickly lost due to the lack of control on the mineral scales currently depositing at the wellbore area. Before go to the lab and test the benefits that an inhibition job can generate in terms of production decline sustainability, several options were simulated in order to predict the most probable gas rate performance.
The options were designed based on experiences reported in other fields in which a scale inhibition strategy has been implemented. For each one of the cases is assumed
a scale inhibition treatment lifetime of 2 years.
?Base Case: The forecast production assuming that nothing is performed in the well.
?P10 Case: Combine stimulation and inhibition job is performed on the well. Skin damaged is not induced during inhibition job. Many corrosion and mineral scale
inhibitors adversely affect the reservoir wettability because their absorption, some
times a preflush stage is included as a part of the job in order to mitigate this
adverse effect.
?P50 Case: This cased is similar to P10 case but assume that some damage is induced in the reservoir during the injection of inhibitor. In this case is also
assumed that the induced damage is being removed as long as the well is
producing.
?P90 Case: This case assumes only stimulation to remove the mineral scale damage and restore the original permeability but does not include inhibition job.
The figures 24 and 25 show the gas rate performance predicted for the previous options. From the graph is very clear that substantial increasing in cumulative gas production can be obtaining from the inhibition jobs. The additional gas produced reserves that can be obtaining for P10, P50 and P90 cases were calculated as 7.1 bcf, 6.6 bcf, and 4.0 bcf respectively
Developing the Engineering Study for Production String
The well H-25 was chosen to analyze the impact that mineral scale deposited inside production string are exerting on well productivity. This well was chosen due to exists direct evidence that mineral scale compounds are really deposited inside of the production string. The figure 26 shows the data logged when a multi finger caliper log was run in November 2007. A relevant reduction in internal diameter can be observed from 6000 to 11626 as consequence of mineral scale deposits. A total amount of 15000 lbs of mineral scales were calculated by using the caliper log data.
The evolution of corrosion and mineral scales inside the production string through the time were calculated using time steps of 1 year. To calculate the average reservoir and production
parameters required in each one of the time steps a simulation run was carried out, again MBAL and PROSPER were used to build the productivity model.
The Oddo-Tomson9 model was implemented to calculate the corrosion evolution and the wall loses in the production string through the time. The figure 27 shows the result obtained which are showing that the corrosion process is taking place at an average corrosion rate of 4 mpy, the cumulative wall loses are calculated as 3% and 13.1% at the top and bottom of the 4-1/2 production string and 5% in the production tubing. The differences observed when compared the corrosion model with caliper logs is explained by scale presence. It is clear that high amount of scales were formed as consequence of corrosion by-products, these scales once deposited on the walls starting to act as a protective coating that probably reduced the corrosion in some parts and eliminated this process in the sites where the scale is deposited.
A similar process like that used to calculate the scales in wellbore area was implemented for the production string. The scale tendency, the potential mass, and the amount of scales deposited through the time were calculated by running prediction software software. The water sample analyzed for this well were saturated with iron to simulate the corrosion process, and additional saturation with calcium carbonate was also required in order to match the amount of scales deposited and that were calculated using caliper log data. The figure 28 shows the cumulative amount of scales deposited in the production string such as were simulated by prediction software; calcite, ferric hydroxide and iron sulfide were the scales identified by the program, the cumulative amount currently deposited inside the production string for each one of the previous mineral scales are 12761, 60.4 and 2528 pounds respectively.
To calculate the effect of mineral scales deposited inside the tubing string a nodal system analysis was performed in each one of the time steps. A solution node was located at the bottom hole condition, the IPR calculated according to the reservoir pressure extracted from MBAL model, and the VLP curves were calculated assuming 0, 5, 10, 20 and 30% of ID reduction in the pipe length area really affected by scales deposits. The figure 29 shows the final results obtained from nodal system analysis and the figure 30 summarize the results in each one of the time steps. The graphs show how the mineral scale deposits inside the production string have been increasing through the time and this situation is also generating additional pressure drops which reduce the well productivity. The calculated current ID reduction in the pipe length in which the deposits are being accumulated is 14.8% and the corresponding gas rate lost due to this reduction is 2.3 MMscfd.
To calculate the benefits that can be obtained from stimulation and/or inhibition jobs a similar procedure like that followed for wellbore area was performed. The options cases are summarized below.
?Base Case: The forecast production assuming that nothing is performed in the well, de-scaling and/or stimulation jobs are not performed in the well.
?P10 Case: This case assumed that a stimulation job as well as de-scaling job were performed on the well to restore original permeability and remove scale deposited inside production string. An inhibition job was also performed to avoid mineral scale precipitation at wellbore area and inside production string; it is also assumed that not damaged is induced during the injection of the inhibitors in the production system.
Because we have not experience or information about commingled inhibition (reservoir and production string) we are limiting the inhibition lifetime to one year.
?P50 Case: This cased is similar to P10 case but assume that some damage is induced in the reservoir during the injection of inhibitors. In this case is also assumed that the induced damage is being removed as long as the well is producing.
?P90 Case: This case assumes stimulation and de-scaling jobs but not inhibition.
The figure 31 shows the gas rate performance modeled for each one of the options and the summary of production data is showed in figure 32. The modeled production data confirm the high benefits that can be obtained in terms of additional gas produced reserves by implementing a strong mineral scale strategy. For the particular case of well H-39 the additional gas produced reserves were 2.2 bcf, 2.1 bcf and 1.3 bcf for P10, P50, and P90 cases respectively during the assumed inhibition lifetime of 1 year.
PROPOSAL TO DEVELOP A STRONG MINERAL SCALE STRATEGY
The previous engineering study gave us the required bases on which a mineral scale strategy should be found. There are two specific points in the entire production system that should be accessed to guarantee the success of any strategy: wellbore area and production string.
For the particular case of Khuff reservoir is clear that the main mineral scale to be combated at wellbore area is calcite. Assuming that no projects related to give pressure support to the reservoir will be implemented in the future then additional work should be performed to mitigate other important scales. Under the current level of reservoir pressure depletion it is very probable that scales like celestite, barite, magnesite, strontianite, anhydrite and brucite will be also depositing at the wellbore area in appreciable amounts.
It was also extracted from the engineering work the negative impact on well productivity being generated by the mineral scales deposited inside the wellbore. The study showed that although this impact could be minimum in those areas in which the reservoir pressure is high, the negative impact on well productivity is increasing and becoming important as long as the reservoir is being depleted. Additional to the negative impact on well productivity, the mineral scales deposited inside the production tubing are generating problems related to well access (limiting the downhole surveillance) and costly operations to clean up the well. The mineral scale strategy should include the required work to look for chemical corrosion inhibitors that can be successful implemented in the field.
The first stage on the future scale strategy should be focused into perform the laboratory work required to find the best in class inhibitors and corrosion that can be applied successfully in Ghawar field. Several important factors related to the type of reservoir fluids, type of reservoir rock, HPHT conditions and mitigation of induced damage should be considered in the work.
Once the chemicals have been identified and additional job should be performed in order to determine the best way of deployment. The engineering study showed that several potential options should be addressed:
?Strategy for wells with mineral scale deposits located only at the wellbore area
?Strategy for well with mineral scale deposits located only inside the production string.
?Strategy for well with mineral scale problems at both sites – wellbore area and production string.
?Strategy to include the inhibition jobs in the current acid stimulation campaign.
The field application, which is being designed to be initially carried out in HRDH wells flowing to HWGP, should be properly tracked in order to get the data required to optimize the strategy to the other gas reservoir currently producing from Ghawar field.
CONCLUSIONS
As described in this paper, an engineering job was performed to identify and understand the mineral scale process currently taking place in the upstream part of the production system. The technical evaluation, performed on the HRDH wells currently flowing to HWGP, cleared the doubt about the mineral scale situation taking place at the wellbore area and confirmed the existence of a negative growing of mineral scales inside the production string.
For the particular case in which this technical work was focused, Khuff reservoir, the work found that a multi-component scale system is taking place in both sites; calcite constitute the main scale being currently deposited at the wellbore area, scales like strontianite, barite, celestite, anhydrite, magnesite, and brucite are expecting to be increasing in importance as long as the reservoir depletion continue. Ferric hydroxide, calcium carbonate and iron sulphide appear to be the most important minerals being deposited inside the production string.
Several simulations runs, in which options commonly developed in similar fields in which already an inhibition campaign has been implemented, were carried out and demonstrated the high benefits that a mineral scale mitigation strategy should be provide in terms of additional produced gas reserves if inhibition treatments are included in the current stimulation campaign.
Laboratory work to find the best in class mineral scale and corrosion inhibitors should be started as soon as possible. The lab work should be complemented with the required study in order to analyze the best option for deployment taking into account the particular mineral scale environment described by this engineering work.
This study, together with the lesson learnt that can be obtained after performed the field pilot test in HARDH wells, should be extended to include the other gas condensate reservoirs currently producing from Ghawar field.
ACKNOWLEDGEMENTS
The authors thank Saudi Aramco for permission to publish this work. We also acknowledge to our general supervisor Mr. Muhammad Al-Khawajah for his continuous encourage writing the paper, and the valuable technical support received from Eng. Jairo Leal and Eng. Ricardo Solares.
REFERENCES
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Component Khuff-B, %/mol Khuff-C, %/mol Hydrogen sulfide 0.00 0.94
Carbon dioxide 1.00 1.61
Nitrogen 8.60 9.06
Methane 76.64 75.6
Ethane 7.62 7.53
Propane 3.26 3.09
Iso-Butane 0.57 0.51
n-Butane 1.15 0.96
Iso-Pentane 0.37 0.27
n-Pentane 0.4 0.26
Hexanes 0.28 0.14
Heptanes 0.09 0.02
Octanes 0.02 0.01
Nonanes 0.00 0.00
Decanes 0.00 0.00 Undecanes 0.00 0.00 Dodecanes plus 0.00 0.00
Gas gravity 0.7176 0.7148
API gravity @ 60°F 46.8 46.2
TABLE 2
Analysis of Solid Samples Recovered in Four Wells Flowing to HWGP
Compound Formula Well-H5 Well-H17 Well-H18 Well-H22 Pyrrhotite Fe7S8 6.0 70.0 18.2 17.0 Greigite Fe3S40.0 15.0 0.0 13.0 Mackinawite FeS 3.0 9.0 10.2 17.0 Calcite CaCO313.0 2.0 7.5 0.0 Dolomite CaMg(CO3)27.0 0.0 0.0 0.0 Siderite FeCO30.0 4.0 0.0 6.0 Troilite FeS 51.0 0.0 0.0 25.0 Akaganeite FeO(OH) 0.0 0.0 0.0 12.0 Iron Chloride Fe2(OH)3Cl 2.0 0.0 0.0 7.0 Halite NaCl 0.0 0.0 3.0 3.0 Barite BaSO411.0 0.0 0.0 0.0 Quartz SiO2 5.0 0.0 1.6 0.0 Pyroaurite Mg6Fe2CO3(OH)16.4H2O 2.0 0.0 0.0 0.0 Iron Oxide Fe2O30.0 0.0 59.0 0.0
Molybdenum
Oxide
MoO30.0 0.0 0.5 0.0
TABLE 1
Typical PVT Data For Khuff-B and Khuff-C Reservoirs.
TABLE 3
Water Composition for HRDH Wells Flowing to HWGP
Well Na+Ca2+SO42-Cl-HCO3-Ba2+Sr2+ ppm ppm ppm ppm ppm ppm ppm Well-H1 48800.0 10400.0 261.0 96300.0 407.0 8.3 710.0 Well-H2 799.0 2380.0 93.0 5690.0 106.0 2.9 18.0 Well-H3 1851.0 526.0 46.0 3880.0 234.0 0.8 30.0 Well-H4 24800.0 7580.0 105.0 55400.0 328.0 8.3 460.0 Well-H5 7770.0 12526.0 104.0 45807.0 100.0 2.0 0.0 Well-H6 77.0 77.0 35.0 52.0 357.0 0.7 7.8 Well-H7 7185.0 4690.0 115.0 22400.0 228.0 3.4 100.0 Well-H8 5683.0 1900.0 88.0 13200.0 112.0 0.6 83.0 Well-H9 9653.0 6860.0 158.0 31600.0 210.0 3.7 150.0 Well-H10 12200.0 2790.0 176.0 24800.0 555.0 4.2 190.0 Well-H11 674.0 653.0 62.0 2670.0 293.0 0.4 14.0 Well-H12 635.0 480.0 60.0 1960.0 45.0 0.4 14.0 Well-H13 4739.0 1820.0 119.0 11000.0 215.0 1.8 86.0 Well-H14 62.0 26.0 20.0 40.0 152.0 0.9 0.2 Well-H15 15600.0 10400.0 156.0 47300.0 176.0 6.3 460.0 Well-H16 3749.0 1600.0 134.0 8960.0 164.0 0.7 85.0 Well-H17 708.0 979.0 275.0 2680.0 296.0 0.3 48.0 Well-H18 7356.0 1590.0 16.0 14800.0 385.0 1.8 110.0 Well-H19 5238.0 1890.0 72.0 12500.0 114.0 0.6 83.0 Well-H20 641.0 608.0 82.0 2200.0 195.0 0.6 20.0 Well-H21 15700.0 3490.0 98.0 32100.0 410.0 4.0 240.0 Well-H22 13300.0 5460.0 131.0 32000.0 154.0 5.2 250.0 Well-H23 7309.0 4220.0 121.0 21000.0 133.0 7.3 190.0 Well-H24 15400.0 7660.0 105.0 40200.0 207.0 3.6 450.0 Well-H25 8338.0 3900.0 210.0 21300.0 212.0 0.7 200.0 Well-H26 22300.0 7200.0 107.0 49600.0 99.0 3.3 20.7 Well-H27 30000.0 6810.0 192.0 60200.0 34.0 5.0 470.0 Well-H28 4031.0 1550.0 140.0 9330.0 171.0 1.5 72.0 Well-H29 1106.0 1070.0 190.0 4100.0 40.0 4.9 470.1 Well-H30 27900.0 6420.0 193.0 56600.0 0.0 5.2 370.0 Well-H31 22300.0 22300.0 243.0 90400.0 0.0 6.2 594.4 Well-H32 1979.0 4140.0 58.0 15300.0 184.0 2.2 37.0 Well-H33 3556.0 2120.0 88.0 10200.0 331.0 2.4 121.7 Well-H34 41400.0 9470.0 160.0 83700.0 2.0 5.1 600.0 Well-H35 610.0 3560.0 72.0 10800.0 204.0 2.9 137.4 Well-H36 3400.0 11100.0 41.0 26700.0 188.0 3.6 68.0 Well-H37 21100.0 17100.0 117.0 70600.0 156.0 7.4 490.0 Well-H38 6571.0 5780.0 315.0 23600.0 0.6 1.6 160.0 Well-H39 5780.0 1860.0 85.0 12300.0 205.0 3.4 58.0 Well-H40 9539.0 13900.0 182.0 51400.0 133.0 2.0 5.0
TABLE 4
Average Concentration For Reservoir Water of HRDH Wells Flowing to HWGP Ion PPM concentration Meq/lt Concentration Na+11623.6 505.4
Ca2+5683.7 113.7
Ba2+ 3.4 0.05
Sr2+ 208.6 4.8
Mg2+ 1038.1 85.1
K+ 752.4 19.2
Cl-30877.1 869.8
SO42- 133.8 2.8
HCO3- 184.1 3.0
TABLE 5
Production Data Required to Calculate Amount of Scale For Prioritised Wells
Water rate Potential mass SG Elapsed Time Well BWPD CaCO3, mg/lt days
Well-H10 30 339.7 1.0311 2021
Well-H1 10 246.0 1.1101 1936
Well-H21 28 236.8 1.0394 1964
Well-H18 18 215.0 1.0181 2123
Well-H32 46 194.2 1.0128 1160
Well-H17 16 172.5 1.0043 2074
Well-H11 26 165.4 1.0037 1974
Well-H6 4 141.5 1.0005 728
Well-H7 24 121.6 1.0276 1930
Well-H13 6 115.9 1.0136 2113
Well-H9 14 113.8 1.0389 2102
Well-H25 26 113.6 1.0262 2010
Well-H35 18 107.1 1.0373 467
Well-H38 34 106.6 1.015 2081
Well-H20 14 103.6 1.0036 1502
Well-H15 14 93.3 1.0574 2070
Well-H31 80 86.7 1.0189 2137
Well-H24 16 86.4 1.0483 2049
Well-H16 10 81.9 1.0114 2157
Well-H3 30 73.3 1.0048 626
Well-H28 4 70.0 1.0116 1122
Well-H22 74 63.0 1.0382 1140
Well-H4 12 57.7 1.0662 1896
Well-H23 26 56.3 1.0253 2070
Well-H36 8 42.0 1.0839 739
Well-H26 12 38.4 1.0572 1987
Well-H39 18 31.4 1.0593 2090
Well-H14 20 19.6 1.0002 809
Well-H34 40 15.3 1.0136 1927
Well-H19 32 1.9 1.0157 2069
Well-H2 38 7.3 1.0077 2134