SPE 94707

Accurate Measurement of the Hydrogen Sulfide Content in Formation Fluid Samples—Case Studies H. Elshahawi, SPE, and M. Hashem, SPE, Shell Intl. E&P Inc.

Copyright 2005, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 2005 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, U.S.A., 9 – 12 October 2005. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435114

Abstract The Hydrogen Sulfide (H2S) content of subsurface hydrocarbon reservoirs has a profound impact on completion, surface production, and process design. The H2S content of crude oil directly impacts the sale value of the produced hydrocarbons, while the H2S content of produced water can result in significant production problems, which can lead to detrimental effects on hydrocarbon transport and sales specifications. In theory, the H2S content of reservoir fluids can be determined from samples collected by wireline formation tester tools. In practice, however, measurement is complicated by the partial-to-total loss of the gas by absorption/adsorption onto the metal components of the downhole tool, storage bottles, and transfer/analysis system, particularly those made from iron. H2S readily forms non-volatile and insoluble metal sulphides by reaction with many other metals and metal oxides, and analysis of the fluid samples can therefore underestimate the true H2S content. Therefore, many practical challenges must be overcome to accurately determine H2S levels in formation tester samples. These include metallurgical design considerations, sampling environment and system selection as well as the timing and type of H2S analyses. This paper details our successes in accurately measuring both high and low concentrations of H2S in downhole formation tester samples. It describes an integrated workflow by which ultra low H2S concentrations can be captured and preserved in formation tester samples until the tool is brought back to surface where the samples can be analyzed. This workflow includes a number of modifications to some commercial formation tester tools and sample chambers to ensure that the bulk of the H2S does not get absorbed by the time the tool arrives to the surface. Downhole measurements made close to

the fluid entry into the sampling tool are used to cross check and verify the surface measurements. Finally, on surface, a number of techniques are used to measure H2S concentration in the sample bottles as soon as practical after the formation tester tool is brought to the surface. The paper demonstrates, through a number of case studies, that by following this comprehensive workflow, it is possible to capture and analyze hydrocarbon samples with minimal loss of H2S, regardless of the levels of H2S being measured. Introduction The presence of Hydrogen Sulfide (H2S) in the reservoir fluid has a major effect on project economics as well as occupational health, safety, and environment (HSE). The accurate measurement of H2S concentrations in the reservoir fluids is critical to the design of completion, surface, and production facilities. With accurate determination of H2S levels in the subsurface, the operator can hope to: - Determine which (if any) HSE measures must be implemented for dealing with H2S at the various stages of exploration, appraisal, development, production, and abandonment of a given prospect.

- Indicate the need for special metallurgical or process design to deal with certain levels of H2S in the presence of various other mitigating or accentuating factors.

- Detect the onset and evolution of reservoir souring upon the implementation of water injection or other enhanced recovery techniques.

The measurement of H2S concentrations in samples collected by formation testers is complicated by the partial-to-total loss of the gas by reaction of the metal components and the drilling/completion fluids. Many practical challenges must be overcome to accurately determine H2S levels in formation tester samples. These include metallurgical design considerations, sampling environment and system selection as well as the timing and type of H2S analyses required.

Sources of H2S in the subsurface Reservoir souring is quite prevalent in the oilfield. It is due to uncontrolled activity of reservoir resident sulfur reducing

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bacteria – SRB’s, which are capable of reducing sulfate to sulfide. It occurs in all subsurface habitats that are conducive to SRB growth, predominantly but not exclusively in fields under seawater flooding. Scott et al. (1993) discussed the formation of hydrogen sulphide by the action of SRB in oil wells which co-produce waters containing high sulphate concentrations. Some 70% of water-flooded reservoirs worldwide have turned sour. The effect of souring typically becomes noticeable when traces of H2S start appearing in produced gas, on or closely behind the breakthrough front of injected water. The abundance of H2S in subsurface hydrocarbon reservoirs results primarily from interactions between the ubiquitous sulphate reducing bacteria and exogenous sulphate under anaerobic conditions. Altogether there are three main mechanisms responsible for H2S generation in petroleum reservoirs:

1) Bacterial Sulfate Reduction This reaction is mainly anaerobic and tends to occur at low temperatures (lower than 80C) and is often triggered by injection of seawater, which tends to be rich in sulfates. The H2S concentrations generated are usually less than 5%, and the chemical reaction takes the following form: Sulfates + Organics + Nitrogen → H2S 2) Theromochemical sulfate reduction (TSR) TSR occurs primarily in carbonate reservoirs that are deficient in iron and at temperatures above 100C. The H2S concentrations generated are usually greater than 10%, and the chemical reactions take one of the following forms: Gas + Anhydrite → H2S + Carbonate Calcium Sulfate + Organic Material → H2S + CaCO3 3) Thermal cracking In these reactions, the H2S is generated by the thermal alteration of the sulfur in the kerogen and occurs at temperatures higher than 140C. The concentration of thermally sourced H2S tends to increase with temperature, and the H2S concentrations generated are usually less than 5% (Hâland et al., 1999).

The most common reaction products of BSR and TSR are identical and include carbonate material, sulfides (usually as base, or transitional metals, sulfur, H2S, and sulfurized or oxidized hydrocarbons). Although knowing the different potential sources of H2S generation are critical in quantifying the abundance of H2S in a given reservoir, understanding the processes leading to removal of H2S from the system (e.g. reactions with iron if available to form iron sulfides) is equally important. Importance of Measuring H2S concentrations H2S is an extremely hazardous, toxic compound that occurs in a number of natural and industrial environments. Naturally, it

can be found in coal pits, sulfur springs, gas wells, and as a product of decaying sulfur-containing organic matter, particularly under low oxygen conditions. Industrial sources of H2S include petroleum and natural gas extraction and refining, pulp and paper manufacturing, rayon textile production, leather tanning, chemical manufacturing and waste disposal. H2S is a colorless, flammable gas. It is approximately 20% heavier than air and so tends to collect in depressions and confined spaces in the ground. It has a very low odor threshold, with its characteristic rotten egg smell easily perceptible at concentrations well below 1 ppm in air. The odor increases as the gas becomes more concentrated, with the strong rotten egg smell recognizable up to 30 ppm. Above this level, the gas is reported to have a sickeningly sweet odor up to around 100 ppm. However, at concentrations above 100 ppm, a person's ability to detect the gas is affected by rapid temporary paralysis of the olfactory nerves in the nose, leading to a loss of the sense of smell. This means that the gas may be present at dangerously high concentrations yet have no perceivable odor. Prolonged exposure to lower concentrations can also result in similar olfactory paralysis effects. Because of this unusual property of H2S, it is very dangerous to rely on the sense of smell to warn of the presence of the gas. H2S is classified as a chemical asphyxiant, similar to carbon monoxide and cyanide gases. It inhibits cellular respiration and uptake of oxygen, causing biochemical suffocation. Typical exposure symptoms include: Irritation of the eyes, nose and throat (0 -10 ppm); headache, dizziness, nausea and vomiting, coughing and breathing difficulty (10 -50 ppm); severe respiratory tract irritation, eye irritation, acute conjunctivitis, shock, convulsions, coma, and death in severe cases (50-200 ppm). Prolonged exposures at lower levels can lead to bronchitis, pneumonia, migraine headaches, pulmonary edema, and loss of motor coordination (JPT Forum, 1971). The presence of H2S in produced fluids can give rise to critical safety problems. The exposure limit recommended by the US National Institute for Occupational Health is 10 ppm per 10 minutes of exposure, and most countries have legal limits in force that govern the maximum allowable levels of exposure to hydrogen sulfide in the working environment. The only reliable way to determine exposure levels is to measure the amount in the air. The human nose can detect concentrations as low as 0.02 ppm with maximum sensitivity at around 5 ppm and becomes increasingly unable to detect H2S at concentrations of 150-200 ppm. Detection limits below about 5 ppm are therefore desirable. Wherever possible, exposure should be minimized by employing adequate engineering controls and safe working practices. Where these cannot adequately control levels of exposure, it may be necessary to supplement them with the use of suitable personal protective equipment (PPE) such as supplied-air respirators (JPT Forum, 1971). Typically, the sulphur content of crude oils is in the range 0.3-0.8% by weight and the H2S content of natural gas is in the range of 0.01-0.4% by weight, but concentrations of H2S in natural gas of up to 30% by weight have been reported

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(Carlson at al., 1996). There appears to be a systematic increase in the sulphur content of crude oils over the past 10-20 years and further increases in the concentration of hydrogen sulphide in both oil and natural gas are anticipated. Hâland et al. (1999) report a correlation between the H2S concentration of produced hydrocarbons from the Norwegian continental shelf and reservoir temperatures in which the H2S content of produced hydrocarbons is negligible below 110C and increases exponentially with temperature above that temperature. Overall, it has been estimated that H2S alone is responsible for about 20% of metal corrosion losses in the petroleum industry. Sulfide stress cracking (SSC) is a form of hydrogen embrittlement that occurs when a susceptible material is exposed to a corrosive environment containing water and H2S at a critical level of applied or residual tensile stress. SSC is commonly observed in high strength or high hardness steels in which the hydrogen is generated by the sulfide corrosion process on the metal surface making the steel less resistant to breakage and generally much weaker in tensile strength (Kane et al., 1998). On a molecular level, hydrogen ions work their way between the grain boundaries of the steel, where hydrogen ions recombine into molecular hydrogen, taking up more space and weakening the bonds between the grains. The formation of molecular hydrogen can cause sudden metal failure due to cracking when the metal is subjected to tensile stress (Wilhelm et al., 1986). To address the problem of hydrogen embrittlement, emphasis is placed on controlling the amount of residual hydrogen in steel, controlling the amount of hydrogen pickup in processing, developing alloys with improved resistance to hydrogen embrittlement, developing low or no embrittlement plating or coating processes, and restricting the amount of in-situ hydrogen introduced during the service life of a part. H2S reacts with Fe from tubulars, valves, etc. to form iron sulfide or "black water". It is important to note that in the last decade, there has been a move away from chemical inhibition due to environmental & engineering limitations (Williams, 2003). The National Association of Corrosion Engineers (NACE) has established guidelines for dealing with H2S in industrial applications. The NACE “Material Requirement” standard MR0175 defines the lower limit for sour service conditions in which sulfide SSC could occur as 0.0003 MPa or 0.05 psia partial pressure. Where partial pressure is defined as the product of absolute pressure and concentration (Fig.1). For example, 10 ppm of H2S at 16,000 psi is equal to a partial pressure of (10/1,000,000)X16,000 = 0.16 psi-partial pressure. There are actually quite a number of factors, other than H2S partial pressure, that affect the susceptibility of a material to sulfide stress cracking. Corrosion rates depend on H2S and CO2 PP, pH, sand and water production, tubular metallurgy, heat treatment, corrosion-inhibitor treatments, temperature, fluid velocity, flow regime, etc (Tuttle, 1990 and NACE 2003). NACE MR0175 paragraph 1.3 lists the following factors: -Chemical composition, strength, heat treatment and

microstructure of the material. Certain compositional elements (for example, nickel in steels) have been identified as SSC promoters. In general, for a particular alloy, as strength and hardness increase, the susceptibility to sulfide stress cracking increases. -Hydrogen ion concentration (pH) of the process environment (Fig. 2). -Total tensile stress (accounting for both applied and residual stresses). -Process temperature. -Exposure Time. Accurate measurement of H2S concentration in sampled fluid is critical to completion, surface production, and process design. The impact on the cost structure is potentially huge. As Fig.3 illustrates, typical completion costs increase by at least one order of magnitude as we move from carbon steel through 13-chrome to high Ni alloys (Kermani, 1995) In theory, the H2S content of reservoir fluids can be determined from samples collected by wireline fluid sampling tools such as Schlumberger’s Modular Dynamics Tester or equivalent sampling tools. Fluid samples are usually collected in metal containers, which can be maintained at Pressure-volume temperature (PVT) conditions that can be directly compared to those at which the samples were collected. However, the problem associated with sampling fluids containing H2S is the partial-to-total loss of the gas by reaction with components, particularly those made from iron-based metals. The H2S gas readily forms non-volatile and insoluble metal sulphides by reaction with many metals and metal oxides, and analysis of the fluid samples can therefore underestimate the true H2S content. Existing H2S Measurement Methods The following methods exist for measurement of H2S in hydrocarbon samples. Often, none of these is sufficient on its own to provide a reliable measurement in low H2S concentrations.

1) Conventional open-hole sampling: Taking samples in openhole environments using formation testers has been carried out for years. High quality PVT samples are achievable with single-phase samplers in Low-shock mode, and sample bottles have been successfully coated with both PTFE and Sulfinert for sometime. However, because of the several other potential sources of H2S loss in the flow paths and pump as well as to the water used to fill the dead volumes of the sampling chambers, open-hole sampling for the determination of low-level H2S concentrations has until recently been considered challenging at best. A combination of lab testing, material improvements, and procedural changes has enabled us to transform openhole sampling into the method of choice for H2S sampling. Part of the improvement has come from switching to a novel sampling technique termed “reverse-low shock sampling” which avoids passing the fluids through the pump altogether (Fig. 4). This will be discussed in more detail later. Another part of the improvement is the successful testing of the practical limits of

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the tools with better coating and preparation for H2S sampling.

2) Surface well testing: Surface separator PVT sampling is another option for H2S analysis. Hence there is a large potential for H2S in the produced fluids to react with the metallic surfaces of the completion/DST string, surface testing flow lines and/or test separator. Scavenging by the mud or completion fluids and partitioning of the H2S into the various phases is also likely. All this can lead to a large undetermined loss of H2S by the time the produced reservoir fluids reach the sample bottle. During extended well tests, where large quantities of fluid are flowed, stability in H2S levels may be achieved although cannot be guaranteed, especially for low H2S concentrations. Onsite analysis during an extended well test has the advantage of repeated measurements with large volumes of liquid and gas to analyze.

3) Cased hole sampling: Capturing down-hole samples in a cased-hole environment has advantages over the previously mentioned methods. Down hole samplers can be positioned very close to the reservoir’s perforated intervals so scavenging of H2S through contact with completions and surface equipment is virtually eliminated. Down hole samplers can be fired when the well is fully conditioned. This means highly representative or “fresh” reservoir fluids can be captured for analysis. The use of single-phase samplers avoids partitioning of trace components between phases and allows controlled flashing of the sample to obtain accurate measurements of H2S in the gas, oil and water phases.

4) H2S coupons: H2S coupons are made of certain metal alloys that corrode or discolor as a result of corrosion solely due to the presence of H2S. The H2S coupon holder is a drop-in replacement for the resistivity cell in the Schlumberger MDT single probe module (Fig.5). From a visual inspection of the coupons upon retrieval to the surface, it will be possible to tell if they have been exposed to H2S. The discoloration results in a loss of the original shiny or glossy finish. The metal turns brown, gray, or black, with a flat matted finish.

A) The most sensitive coupon will turn black when exposed to H2S in levels less than 0.005 psi partial pressure. This is 10 times less than the NACE corrosion limit, but is high enough for human safety problems. B) The mid sensitivity coupon will turn more of a brown color when exposed to H2S levels in the 0.018-0.025 psi partial pressure range. This is just below the level at which significant sulfide stress cracking (a form of corrosion) will occur, but a level at which there is a lethal health risk.

C) The least sensitive coupon will turn a brown color when exposed to H2S levels in the 0.05-0.10 psi partial pressure range. This is enough H2S to require special chrome alloy materials to prevent sulfide stress cracking which then leads to material failure.

5) H2S electrochemical sensor: This sensor is capable of continuously detecting and measuring the H2S concentration as the fluid is extracted from the formation into the sampling tool. The sensor device is deployed along the flowline immediately behind the probe to minimize reactive loss of H2S. It is based on a molecular reaction system developed by Oxford University, involving an electrochemical catalysis mechanism in which the concentration of H2S is proportional to the magnitude of a current function generated at the surface of a diamond electrode (Parrillo et al., 1997). The sensor is interfaced with the fluid flowline using a gas permeable membrane, through which gas species dissolved in formation oil such as methane, carbon dioxide together with hydrogen sulfide will be allowed to enter the reaction chamber, but the system is so specific that only the target species (H2S) will trigger the specific chemical reaction and lead to the signal output. The current design of the H2S sensor design is probably sensitive to target species up to 100 ppm in concentration. Sampling and Measurement of Low level H2S As mentioned before, it is a challenge to accurately measure low (ppm) levels of H2S in formation fluids based on analysis of formation tester samples. Many practical challenges must be overcome to accurately determine H2S levels in formation tester samples. Four key areas need to be addressed in order to achieve this goal:

1. Metallurgical modifications and non-reactive coating 2. Sampling environment and system selection 3. Downhole Measurements 4. Timing and type of fluid analysis

By following a systematic approach, it is possible to capture and analyze samples with very minimal loss of H2S.

Metallurgical modifications and non-reactive coating Trace elements such as H2S, mercury or mercaptans are known to react with the stainless steel walls of the sampling tools and transportation cylinders. Even after a short period of contact, without special precautions, a significant proportion can be adsorbed on exposed metal surfaces, and the H2S will not be detected at the correct level in field or laboratory analysis. If, on the other hand, the reservoir fluid, were to contain high levels (percentage levels) of H2S, then the metals will remove a relatively small part of the H2S, such that the lab analysis will still find high levels of H2S. In either case, without truly effective and reliable non-reactive sample transfer and analysis equipment, the accurate determination of H2S is not possible. By implementing a holistic combination of tool modifications, procedural changes, and improved measurement techniques, it is possible to reduce H2S scavenging levels to a levels close to nil and to preserve low (ppm) levels of H2S until they are accurately and reliably measured on surface.

Ideally, sample bottles should be made of an inert material, but such materials are generally quite expensive. The Baker Atlas RCI sample bottles are made of NP-35N, which is

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unique in its ultra low H2S absorption, but other commercially available sample bottles, including the Schlumberger MDT and Halliburton RDT chambers are typically made of Monel steel or Inconnel which are not as inert. Special materials can be used for bottle coating in order to render these types of bottles inert or non-absorbing to H2S. A number of non-reactive surface coating technologies have been developed over the last 5 years. These coatings allow standard sampling bottles to be converted to non-reactive ones that can be used to capture and store representative samples for H2S and other sulphur compound analysis. PTFE derivatives have been used for coating in the past with demonstrated efficacy. A sample of 40ppm of H2S concentration introduced into a PTFE-coated bottle can generally be recovered after a typical bottom-hole sampling cycle with a level of 38ppm. This compares favorably with losses of 40% or worse if no special precautions are taken. The main drawback of PTFE coatings is that they do not survive multiple uses and that they are rendered essentially ineffective by excessive friction with the sampling and/or agitation piston(s).

Silicon-based coatings are the latest generation of non-reactive coatings offering enhanced characteristics, even compared to PTFE-derived coatings. Silicon-based coatings display a very high level of inertness to H2S comparable with PTFE coatings and have the advantage of being more durable. While single-layer silicon-based coatings (e.g. Restek’s Silcosteel coating) already offer low ppm sulfur sample storage advantages over PTFE coatings, multi-layered silicon-based coatings, such as Restek’s Sulfinert, are even more inert. The non-reactive layer is integrated into the lattice of the sampling equipment’s steel surface offering considerably improved durability. This fact, along with increased hardness, dramatically improves the reliability of a Sulfinert coating over its service life. Independent laboratory tests confirm that Sulfinert multi-layered silicon-based coating is effective with 98% retention of approximately 50 ppm by volume H2S concentration after 6 days of sample storage (Fig. 6). Sampling environment and system selection The materials used in formation testers will react with H2S in the flowing fluid from the formation. As a result, when a fluid sample is subsequently analyzed, the measured concentration of H2S is artificially depressed. If the original concentration in the reservoir is sufficiently low (tens of ppm’s), the sampled fluid may have no measurable H2S left. Many formation tester tools make use of “H2S-resistant” materials that prevent the formation of microcracks, which would otherwise weaken the metal, but these materials may still react with the H2S. In other words, inert materials are always H2S-resistant, but the reverse is not always true. The internal flow line is another item that warrants attention. The internal flowline of formation testers is typically one-fifth to one-quarter of an inch in internal diameter and is made of Monel-K-500, Titanium, or Aluminum-Bronze. In a typical formation tester tool string, the fluid may travel across a total of 20-40 square inches of flowline at a relatively constant rate of around 1 liter/minute while pumping. It has been shown by

experiments that both titanium and Inconnel are largely non-reactive compared to Monel, which is very reactive and allows only a small fraction of the H2S (typically less than 20%) to pass through. Elastomer seals can also contribute to H2S adsorption, but are rather slow to soak up the H2S, and hence are not a problem as long as pumping is fast enough and is continued for sufficiently long period. The pumping unit is the biggest culprit when it comes to H2S absorption. Fluid movement across the internal surface of the pump is intermittent. Typically, fluid is withdrawn into one side of the pump in about half a minute while it is being pushed out of the other, and then the sequence is reversed for another half minute. Depending on when the fluid enters and exits his leads to an average residence time of half a minute. In Schlumberger’s MDT Modular Dynamics Tester, the pump displacement unit has a Monel K-400 surface area of slightly over one hundred square inches and an Aluminum-Bronze surface area roughly a quarter of that in addition to a magnet used for switching the displacement unit travel direction. This arrangement will generally scavenge upwards of 30% of low H2S concentrations (less than 50 ppm) within the half-minute average residence time (Fig.7). To decrease the scavenging of H2S in the tool, non-reactive, or inert, materials must be used. In our test well, the primary sampling probe is equipped with a special flow line linkage material. Parts especially made of Inconel or coated with Sulfinert are used to replace certain components of the tool, ordinarily made of Monel, that are in the flow line or otherwise in the path of the fluid as it travels from the formation to the sample bottle. Bottle coating also does not address the problem of scavenging in the pump itself, which is the major H2S scavenger in the tool and which cannot generally be coated. To circumvent that problem, a dedicated multi-sample module is placed immediately below the bottom probe and used to sample the zones suspected of containing H2S. The bottles in this multi-sample module are filled against a water cushion rather than not using the conventional “Low Shock” technique. A dedicated pump is used below the multi-sample module to pump the water cushion out and into the wellbore in a controlled fashion, thus avoiding scavenging of the H2S in the pump. Using this method, termed “reverse low shock sampling,” control of the flow regime and prevention of phase segregation upon retrieval to the surface are as good as with conventional low shock sampling (Fig.4).

Downhole Measurements H2S coupons and/or downhole H2S detectors can be used to confirm that the concentrations measured on surface are indeed representative. H2S coupons will react specifically to the presence of low levels of H2S when exposed to fluids entering from the formation. Since two single probes are normally run in combination, one H2S coupon holder can be run in each probe to allow another opportunity for H2S detection (e.g. in another zone) or allows the backup probe to be used for the most H2S-prone zone only while leaving the main probe to detect the maximum overall H2S exposure encountered in all the sampled zones. Alternatively, the

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continuous measurement sensor can replace one or more of the H2S coupons In theory, H2S coupon discoloration is largely a function of partial pressure and is weakly dependent on temperature and exposure time. Reservoir waters with no H2S and drilling fluids are not supposed to cause discoloration of these metals. As a result, these alloys are said to be ‘specific’ to the presence of H2S. The reality is more complex, however, and spurious results related to phase partitioning, adsorption, and/or flow velocity could often be observed. Measurement of discoloration in H2S coupons is somewhat subjective. For instance, it is possible to obtain a ‘tarnish’ of the metal rather than true corrosion. This tarnishing in which the metal remains glossy or shiny can potentially be misinterpreted as H2S exposure. Moreover, H2S coupons are quite limited in the range of measurement (up to 0.1 psi partial pressure) and are only good for determination of maximum exposure levels seen by a given coupon. The H2S sensor appears to be a promising development. It enables multiple insitu measurement of H2S concentration in hydrocarbon and water samples; avoid problems of loss in sample bottles. However, the performance of the sensor, most importantly its accuracy and resolution, still needs to be tested under downhole conditions, particularly at low concentrations. For one thing, the relationship of H2S concentration in the buffer fluid to concentration in flowline fluid maybe difficult to determine under downhole conditions unless equilibrium had been established. How long that would require is still unknown. The exposure time and measurement lag time needed as well as the possible effects of temperature, water, mud and other contaminants are but examples of issues that still need to be ironed out. It is our view that calibration of the downhole measurement to widely accepted surface measurement standards would still require time and effort to complete. Even if fully tested and developed, it will still require samples to be taken, much in the same way as other downhole measurements of fluid properties still requires samples to be collected for comparison and calibration. Rather than obviating the need for H2S sampling, this sensor complements and enhances the applicability of the H2S sampling procedure described in this document and help optimize its use by providing real-time H2S measurements that can be used to estimate the H2S concentrations downhole and to intelligently decide on the optimum depths and time intervals to sample the fluid for H2S. . Timing and type of fluid analysis Selecting the most appropriate time for any analysis to be carried out and the most suitable type of analysis to be performed will also have a very large bearing on the accuracy of the results obtained. Several methods are used to detect the H2S concentration on surface. The accurate determination of the H2S content in a hydrocarbon sample is a very difficult task given the reactivity of that compound. There is a clear benefit for immediate onsite analysis with subsequent lab analysis to support the onsite result. A precise measurement in the PVT laboratory does not take into consideration what has

been lost during transportation by adsorption, a reversible phenomenon, and absorption, an irreversible chemical reaction. (Bethea et al., 1973) It is recommended that measurement of H2S contents of gases and oils is carried out at the wellsite immediately after sampling. Measurements carried out in the laboratory, after sampling onsite, should only be used to provide approximate lower bounds on the H2S concentration. For onsite analysis, several methods are considered. The accuracy of the methods is not equal and can lead to significant differences. The ideal solution is to combine several methods and operate according to a referenced standard. This approach allows one to know how much one can trust the results obtained.

- Multigas Monitors: Relies on electrochemical sensor, and provides quick, easy to read digital output, limited to a max concentration of 1000 ppm (Williams et al., 2003).

- Gas detection (length of stain) tubes: Uses the ASTM D4810-88 standard (re-approved 1994) “Method for Hydrogen Sulphide in Natural Gas Using Length of Stain Detectors”. Gas detection tubes are quick, easy to use, and inexpensive. Various manufacturers including Dragger, Kitagawa, GasTec, etc. produce gas detection tubes that can be used in the range of 0.5 ppm by volume to 40% by volume with reasonable accuracy with appropriate range selection, use, storage, and ambient corrections although the majority of these applications will be on the lower end of this range (<120 ppm) (Volkan et al., 1998).

- Potentiometric titration. Uses the following standards: UOP 163-89-H2S and Mercaptans in Hydrocarbon Liquid, IP 272/71 and UOP 212/77-H2S, Mercaptans and Carbonyl Sulphide in Hydrocarbon Gases. The potentiometric titration method is used to determine hydrogen sulphide, mercaptan sulphur and carbonyl sulphur in hydrocarbon gas and liquid in the 0.1 to 1-ppm level and the 1-ppm or higher level. UOP 212/77 can be used for H2S in both the gas and liquid phase. while UOP 212/77/IP342 can be used to check the liquid phase for any H2S left behind and non-volatile mercaptans. Samples may be analyzed directly if viscosity permits injection by syringe. Samples having a high content of sulfur may be analyzed after dilution with a suitable solvent. Halides in excess of 10 times the sulfur level, nitrogen content greater than 10%, and heavy metals may interfere with the analysis. This method is recommended to H2S concentrations that are above 0.3 to several thousand wt-ppm, and is also used for H2S and mercaptans in liquid above 1.0 ppm (Bethea, 1973).

- Iodimetric titration (ASTM D2385) uses the following standards: ASTM D2385-81 standard (re-approved in 1990, discontinued in 1995), IP 103/70 (re-approved proved 1978, no later version currently available), GPA STD 2265-ASTM D 2385-IP103. The technique uses cadmium sulphate adsorption followed by iodometry. This method is very accurate but is rather time consuming with each titration taking 4-6 hours. The Cadmium sulphate method is applicable,

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according to the ASTM D2385, in the range of 0-5 grains of H2S per 100cu-ft, corresponding to a range of 0-115 mg/mcu or 80 ppm by volume (Bethea, 1973).

- Tutwiler method: Uses the UOP 9-59 standard. UOP 9-59 is adapted to H2S concentrations that are above 5 grains/100 cu-ft which corresponds to 80 ppm by volume. It is a wet chemistry method that takes over from the Iodimetric titration method for concentrations above the limit of 80 ppmv.

- Gas Chromatography: uses the ASTM D 1945-91, GPA 2261-90 standard. The gas chromatography technique (ASTM D 1945-91) is used to determine H2S content in gas. This method is recommended for H2S concentrations above 20 ppm up to 40% by mol. Recent developments is micro-GC technology appear promising in being able to extend the applicability of GC methods to even lower concentrations.

For low H2S concentrations in the low tens of ppm range, it is recommended that, as a minimum, gas chromatogrrahpy, gas detection tubes and a wet chemistry method should be used at the wellsite

When analyzing bottles on surface, some ordinary (non-coated) bottles are also analyzed to ensure that the measurement that is made is indeed indicative of true H2S concentrations and are not simply a measurement artifact. For low tens of ppms levels of H2S, one should expect to find no trace of H2S in the uncoated bottles. Case I: Low PPM H2S Concentrations This example illustrates that it is possible to accurately measure low (ppm) levels of H2S in formation fluids based on analysis of downhole samples acquired by formation testers. This test was performed in a well using a specially modified MDT, coated SPMC Single Phase Multisample Chambers, and a mobile analysis lab. The tool string is shown in Fig.8. Some MDT components normally made of Monel were replaced with Inconel ones to minimize H2S scavenging. Two pumps were run, one above for standard low shock and another at the bottom for “reverse low shock” (Fig.4). A dedicated multisampler with Sulfinert-coated bottles placed at the bottom of the string was used for H2S sampling. The bottles in that multisampler were filled against a water cushion using the bottom pump, thus avoiding H2S scavenging by the pump displacement unit. In the description that follows, all chambers are uncoated unless otherwise mentioned. First Sampling depth Pumped 4680 cc in 4.9 min + 12285 cc in 142 min and then filled a few samples to secure a sample although real-time contamination monitoring showed that OBM contamination was still high. Thereafter, filled MRSC 097, MPSR 1932, SPMC 022, SPMC 025, and MPSR 1943.

Analysis results showed fluid from MRSC 097 (uncoated) showed 0 ppm H2S (scavenged) and 1% CO2. Two sub-samples from this chamber showed: OBM 35 wt% in STO, API 42.34 and OBM contamination of 33 wt% in STL, and API 42.3 and no H2S. After that, 3510 cc were pumped over 30 min with the bottom pump. This was followed by filling coated SPMC 226. No H2S analysis was attempted on this coated bottle due to high level of OBM contamination. Second Sampling depth Pumped 34515 cc in 49.3 min with bottom pump and filled: two Sulfinert-coated bottles: coated SPMC 159 and coated SPMC 118. Analysis results showed coated SPMC 159 with 9 ppm H2S, 1% CO2, OBM contamination of 15.3 wt% in the STL, and 13.5 wt% in the live oil, contaminated gravity of 39.84 API, and cleaned gravity of 38.45 API After that, pumped 41535 cc in 43 min with top pump and filled: MRSC 101, MPSR 1268, and coated SPMC 009. Results: MRSC 101 sub-sample measured 9.04 wt% OBM contamination in STL, 7.6% OBM contamination in live oil, 899 scf/bbl, and API 40.68. Another MRSC 101 sub-sample yielded 8.42 wt% OBM, 906 scf/bbl GOR, 40.50 API, 0 ppm H2S (all adsorbed), corrected gravity of 39.8 API, and corrected GOR of 994 scf/bbl. Third Sampling depth Pumped 51480 cc in 84.19 min with top pump and filled: MPSR 458, MPSR 1155, and coated SPMC 113. After than, pumped 13455 cc in 23.46 min with bottom pump and filled coated SPMC 168 and coated SPMC 037 Analysis if coated SPMC 168 yielded 965 scf/bbl GOR, 41.2 API, 5.1% OBM contamination in STL and 4.6 wt% OBM contamination in live oil. API gravity corrected for OBM was 40.8 API, and GOR corrected for OBM was 1019 scf/bbl. SPMC 037 yielded 13 ppm H2S concentration, 1% CO2, OBM contamination of 4.79 wt%, and 40.26 API.

Fig.9 shows that the H2S coupons came up with exposures that are highly consistent with the values measured on the coated bottles. This provided confidence in the results. Note also that, as expected, none of the uncoated bottles showed any H2S, which demonstrates the value of the special procedures used.

Case II: Low H2S Concentrations An H2S adsorption test was conducted by using a full Baker Reservoir Characterization Instrument (RCI) string (Shammai,

8 SPE 94707

2004). The tool was assembled as shown in Fig.10 and consisted of the hydraulic section, the packer section (MB), the 56cc pump (BB), the 500cc pump (RB), and the six tank carrier (WA). Two pumps, a six-tank carrier, two stock solutions (batch #1 and batch #2), and a vacuum pump were used. The purpose of the experiment was to estimate the amount of H2S adsorbed while pumping sample through an RCI string. This was achieved by preparing 20 Liters of standard solution of brine containing approximately 60 ppm of H2S. The solution was then pumped through the tool to simulate exposure to H2S. In this experiment two pumps were used to pressurize the sub-samples in the six tank carrier to 3000psi and 5000psi. Two sub-samples were collected from the tanks containing the stock solution, designated as batch #1 and batch #2. These samples were labeled sample number 7 and sample number 8 respectively. Batch#1 and Batch #2 stock tanks, were connected by a Tygon tubing on the sample side.

Four single-phase tanks were prepared with 500psi of nitrogen charged in two tanks (samples #1 and #3 as shown in the above diagram) and 1000psi of nitrogen charged in the remaining two (samples #2 and #4 as shown in the diagram). Then all four tanks were loaded into the six-tank carrier. Compressed air was blown through the tool to remove all excess water from the sample line, and the tool was function tested to make sure that the valves and the pumps will operate without problems. The manual valves of the single phase and the borehole tanks exit tanks were then opened, and the system was evacuated for 2 hours. Diesel was then pumped through the tool for 30 min to make sure air had been eliminated from the system. For clarity, the experimental procedure could be divided into two parts. Part One The 56cc BB pump was activated, and 4 liters of sample was pumped from Batch #2 stock solution through the tool to displace the diesel and expose the tool to the H2S solution (Batch #1 remained closed at this step). 200c of sample was displaced into the borehole exit tank. This sample was labeled sample #5. 4 liters of stock solution batch #1 was then pumped through the tool using the BB pump. The single-phase tank filled with 500psi nitrogen pressure was opened, and enough sample volume was pumped into the tank to produce a pressure equal to 3000psi. This sample was labeled #1. The single-phase tank, which contains 1000psi of nitrogen was opened, and enough sample was pumped into the tank to produce a sample pressure equal to 5000psi. This sample was labeled #2. An attempt was made to collect a sub-sample from the stock solution (Batch #2), but there was not sufficient sample available. The 500cc RB pump was activated and batch 1 stock solution tank was opened. 4 liters of sample was pumped from Batch #1 stock solution through the tool to displace the diesel in the pump (Batch #2 remained closed at this step). 200cc of sample was displaced into the borehole exit tank. This sample was

labeled sample #6. 4 liters of stock solution Batch #1 was then pumped through the too using the RB pump. The RB single-phase tank, which contained 500psi of nitrogen, was opened. Then enough sample volume was pumped into the tank to produce a sample pressure equal to 3000psi. This sample was labeled #3. The single-phase tank, which contains 1000psi of nitrogen, was opened. Enough sample was pumped into the tank to produce a sample pressure equal to 5000psi. This sample was labeled #4. A sub-sample was collected from the stock solution (Batch #1). This sample was labeled #9. As summarized in Fig.11 and in the top part of Fig.12, a total of three samples were collected; one at the borehole exit with final concentration of 60.3ppm, a second sample at 3000psi with final concentration of 56.7ppm, and a third sample at 5000psi with final concentration of 56.6ppm. The results indicated an approximate loss of 3ppm in the pressurized samples and no loss in the borehole exit sample. The “Delta” column in Fig.12 indicates the difference between the average H2S concentration value of the stock solution (batch 1) and the final H2S concentration in the samples collected during the test. The stock solution in batches 1 and 2 contained 60ppm of H2S. For Batch #1, two samples were collected one before the test and one after the test. The results indicated that there was no appreciable deterioration in H2S concentration during the experiment. For Batch #2, there was not sufficient sample left in the tank at the end of the experiment to collect a sub-sample. Part Two In the second part of the experiment, batch #2 was used along with the 56 cc BB pump. Three samples were acquired; first one at the bore hole exit with final concentration of 58.6ppm, second a sample collected at 3000psi with final concentration of 59.0ppm, and third a sample at 5000psi with final concentration of 60.4ppm. The results shown in the lower part of Fig. 12 indicated a loss of less than 2 ppm in the pressurized samples and a loss of 1ppm in the borehole exit sample. The “Delta” column indicates the difference between the H2S concentration value of the stock solution (Batch #2) and the final H2S concentration in the samples collected during the test. H2S concentration in the stock solution remains constant during the experiment. After concluding the tests with the RCI, it was felt that enough understanding of what the potential for loss of H2S was with the RCI. Two jobs were attempted with the results in mind and using the same analytical procedures described for Case I. One job was carried with the RCI, samples yielded 23 ppm compared to 28 ppm with from an extended well test. On another well, 11 ppm was measured on the RCI samples vs. 15 PPM from a corresponding DST. As a result of the lab experiments and the field trials, the following conclusions were made: 1. H2S adsorption in the RCI tool string and sampling tank

is not dependent on time, pressure, or temperature (up to 400°F and 7 days).

SPE 94707 9

2. The Baker RCI is currently the most suitable for sampling low level H2S because of its titanium construction.

3. Approximately 3 to 5ppm of H2S are adsorbed by the tool string regardless of the original concentration of the H2S in the sample.

Case III High Levels of H2S concentration In this example, the MDT was run in two wells in the Middle East and the measured H2S results were compared to ones recorded on DST’s. Prior to conducting the tests, lab experiments were conducted using a set-up similar to the RCI setup described above. As expected and illustrated in Fig.. 7 , the experiments demonstrated that absorption of H2S in the MDT pump unit is strong at low levels (<50 ppm). However, since the interest in this project was to measure much higher levels of H2S, the objective was primarily to find out what quantity of a 1% H2S solution would be needed to saturate the exposed surfaces of the tool such that no further loss of H2S would occur over the course of the sampling. The experiments revealed that the critical number to saturate a typical MDT string is 35 gal for concentrations of 50,000 ppm or more. The actual analysis results were in excellent agreement with the expected results. In one of the test wells, 0.61% H2S was observed in the sample compared to 0.62% in the well test, while on the other well, 1.1% was observed in the MDT samples compared to 1.12% in the well test. Conclusions We have demonstrated that different levels H2S concentrations can be accurately measured in downhole fluid samples. The key is in understanding the factors that affect the measurement and in using a comprehensive process/workflow. Depending on the H2S levels of interest, the process may include a number of modifications and replacements to several parts of the formation tester tool and to the sample chambers themselves to ensure that the bulk of the H2S does not get absorbed by the time the tool arrives to the surface. For low (PPM) levels of H2S, the RCI seems to be the most suitable tool because of its titanium construction. Moreover, MP35N, the material used in the RCI single-phase tanks, is excellent for preservation of low H2S concentrations. When using other tools such as the Schlumberger MDT or Halliburton RDT, the process must also include rearrangement of sampling modules to eliminate H2S absorption in the downhole pump, which is generally the major culprit for H2S absorption. On surface, a number of techniques can be used to measure H2S concentration in the sample bottles, but this must be done as soon as possible after the formation tester tool is brought to the surface. In addition, downhole measurements made close to the fluid entry into the sampling tool are used to cross check and verify the surface measurements. By using a holistic systematic approach to H2S sampling and analysis, it is now possible to capture and analyze subsurface fluid samples which accurately represent the concentrations in the reservoir fluid regardless of the original concentrations.

References 1. Bethea, R.M., “Comparison of hydrogen sulfide analysis

techniques”, J. Air Poll. Control Assoc., 23, 710-713 (1973).

2. Carlson, M.R. and Cawston, W.B., “Obtaining PVT data for very sour retrograde condensate gas and volatile oil reservoirs: A multi-disciplinary approach”, SPE Gas Tech. Conf., Calgary, April-May 1996, SPE 35653.

3. Hâland, K., Barrufet, H.P., Rønningsen, H.P. and Meisingset, K.K., “An empirical correlation between reservoir temperature and the concentration of hydrogen sulfide”, 1999 SPE Intl. Symp. Oilfield Chem., Houston, Texas, Feb. 1999, SPE 50763.

4. JPT Forum, “H2S – A toxic gas that can kill,” Journal of Petroleum Technology, March 1971, Paper SPE 3202.

5. Kane, R.D., Greer, G.B., “Sulfide stress cracking of high strength steels in laboratory and oilfield environments,” Journal of Petroleum Technology, Nov 1977, SPE 6144.

6. Kermani, M.B. and Harrop, D., “The impact of corrosion on the oil and gas industry,” 1995 Middle East Oil Show & Conference, Bahrain, SPE 29784.

7. NACE (2003), NACE Standard TM0177-96, “Laboratory Testing of Metals for Resistance to Specific Forms of Environmental H2S Environments”, (Houston, TX; NACE International).

8. Parrillo, D.J., Thaeron, C. and Sircar, S., “Separation of bulk hydrogen sulfide — hydrogen mixtures by selective surface flow membrane”, A.I.Ch.E.J., 43, 2239-2245 (1997).

9. Scott, P.J.B. and Davies, M., “Souring of New Irian Jaya wells traced to indigenous bacteria”, Oil & Gas J., 91, 47-50 (1993).

10. Volkan, M., Eroglu, T., Eroglu, A.E., Ataman, O.Y. and Mark, H.B., “A novel sorbent tube for ambient hydrogen sulfide determination”, Talanta, 47, 585-593 (1998).

11. Wilhelm, S.M. and Kane, R.D., “Selection of materials for sour service in petroleum production,” Journal of Petroleum Technology, October 1986, PP 1051.

12. Williams, J.M., “Getting reliable on-site H2S and CO2 concentrations for anti-corrosion measures in gas wells,” SPE 13th Middle East Oil Show & Conference, Bahrain Jun 9-12, 2003, SPE 81495.

13. Shammai, M et al., “Optimum sampling techniques for fluid

samples containing H2S,” presentation at the SPWLA Spring Topical Conference, Taos, New Mexico, March 28 – April 1st, 2004.

10 SPE 94707

Fig.1 H2S Partial pressure plot from NACE MR0175-2000 standard

Fig.2 PH and H2S are related in the NACE MR0175-2000 standard

RAW MATERIAL BAR STOCK

ALLOY $/lb.4130 1.0

4140 1.0

9Cr 1.5

410-13Cr 2.0

420 Mod. 2.0

17-4 3.0

304 2.5

316 3.0

S13Cr 5.0

450 6.0

918 5.5

Monel K-500 12

925 11.5

718 12

625M 20

725 20

C-276 50

MP35N 60

Fig.3 Comparative cost of raw material bar stock

Fig.4 Schematic of the reserves-low-shock sampling technique

SPE 94707 11

Fig.5 H2S coupons shown before and after exposure to H2S

Fig.6 H2S absorption in different types of sample bottles

Before Exposure

After Exposure

mostsensitive

midsensitive

leastsensitive

mostsensitive

midsensitive

leastsensitive

Test 4.1 - Displacement Unit (Side 1) with 50 ppm Test Gas

0.010.020.030.040.050.0

0.1 1 10 100 1000 10000

Time (minutes)

H2S

Con

cent

ratio

n (p

pm)

Test 4.1 - Displacement Unit (Side 1) with 50 ppm Test Gas

0.010.020.030.040.050.0

0.1 1 10 100 1000 10000

Time (minutes)

H2S

Con

cent

ratio

n (p

pm)

Fig.7 H2S Scavenging in MDT Pump Displacement Unit

Fig.8 MDT Toolstring used in Case I

12 SPE 94707

Fig.9 H2S coupon exposure results for Case I

Fig.10 RCI experimental setup – Case II

Fig.11 RCI experimental results – Case II, Part 1

Batch #1 Concentration [ppm] Delta500cc Pump @ 3000psi 56.7 2.95500cc Pump @ 5000psi 56.6 3.05500cc Pump@ Borehole 60.3 -0.65ExitStock Solution Before 59.1the ExperimentStock Solution After 60.2the Experiment

Batch #1 Concentration [ppm] Delta500cc Pump @ 3000psi 56.7 2.95500cc Pump @ 5000psi 56.6 3.05500cc Pump@ Borehole 60.3 -0.65ExitStock Solution Before 59.1the ExperimentStock Solution After 60.2the Experiment

Batch #2 Concentration [ppm] Delta56cc Pump @ 3000psi 59 1.156cc Pump @ 5000psi 60.4 - 0.356cc Pump@ Borehole 58.6 1.5ExitStock Solution Before 60.1the ExperimentStock Solution After Insufficient the Experiment sample

Batch #2 Concentration [ppm] Delta56cc Pump @ 3000psi 59 1.156cc Pump @ 5000psi 60.4 - 0.356cc Pump@ Borehole 58.6 1.5ExitStock Solution Before 60.1the ExperimentStock Solution After Insufficient the Experiment sample

EBMBBBWA3000psi

5000psiRB

DieselVacuum Pump DieselVacuum PumpVacuum Pump

3000psi

5000psi

#1

#2

#3

#4

RB BB

#5#6

RB BB

#5#6

Batch 1

Batch 2

# 7 and # 9

# 8

Batch 1

Batch 2

# 7 and # 9

# 8

Bore-hole Exit Tanks

Fig. 12 Summary of RCI Experimental Results – Case II, Parts 1 and 2

Sample # Batch # 1 Batch # 2 Concentration Delta [ppm]

Sample 1 BB pump @3000psi 59.0 1.1

Sample 2 BB pump @5000psi 60.4 -0.3

Sample 3 RB Pump 3000psi 56.7 2.95

Sample 4 RB Pump 5000psi 56.6 3.05

Sample 5 BB pump

Borehole Exit 58.6 1.5

Sample 6 RB pump

Borehole Exit 60.3 -0.65

Sample 7 Stock solution before the test 59.1

Sample 8 Stock solution before the test 60.1

Sample 9 Stock solution after the test 60.2