bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydrogen Sulphide Measurements In SAGD Operations-Part II
Authors: Thim H.F. 
Published: March 2010

Abstract
In a previous paper, a method suitable for the measurement of hydrogen sulphide concentrations in SAGD process streams was described. The method is applicable to measuring hydrogen sulphide, non-condensable gases, and steam in lines or units containing up to 70% steam, and avoids the errors inherent in stain tube and Tutweiler measurements.
This paper describes the extension of the method. It is now possible to modify the method to accommodate steam concentrations as high as 98.5% at one extreme, and very dry gases at the other. In each case, modifications of the original train that are required to obtain accurate data are described.
Procedures for meeting regulatory requirements, such as hydrogen sulphide and sulphur dioxide emission measurements, are also described.

Introduction
In a previous paper, a new method for sampling of produced from SAGD facilities was described(1). The method is capable of accurately measuring hydrogen sulphide concentrations, and was shown to be superior to the commonly used stain tube methods. The latter methods were shown to deviate from true concentrations by as much as an order of magnitude. This deviation is thought to be due to the presence of a high mole fraction of steam in the facilities under test.
The method also gives the mole fraction of steam, and that of the total non-condensable gases. The standard error was calculated to be of the order of 5.3%, provided it was possible to collect a sufficiently large volume of non-condensable gas. The upper limit of the method is reached when the steam mole fraction exceeds 70%. A schematic of the sampling train is shown in Figure 1.
Over the last three years, it became necessary to measure hydrogen sulphide concentrations in SAGD facilities under more extreme conditions. In the first case, a hydrogen sulphide concentration was required for a facility gas containing a mole fraction of steam in excess of 98%. In the second case, the gas in the facility was almost dry. Both cases presented significant challenges to measurement, as described in the following.

Design of Original Sampling Train
In the sampling train shown in Figure 1, all of the steam is forced to condense early in the train, regardless of the quality of the steam. The hydrogen sulphide is chemically trapped in the same location in the train, by use of a copper sulphate solution.
Use is made of the reaction:
Cu2+ + H2S →CuS + 2H+
The content of condensed water after the test is easily measured by weighing both the first impinger and the drying tube, before and after the test. The solution containing the precipitated copper sulphide is then quantitatively recovered from the impinger in the field, and the copper sulphide separated in the laboratory. Chemical dissolution of the separated precipitate then permits analysis of the total amount of copper recovered, and calculation back to the amount of hydrogen sulphide trapped. Correction for the precipitate mass is then made to the water weight.
Reverse Circulation Placement Technique vs. Conventional Placement Technique: A Comparative Study of Cement Job Hydraulics Design
Authors: Kuru E. , Seatter S. 
Published: March 2010

Abstract
Reverse circulation cement placement technique (RCCPT) has been suggested asan alternative for providing proper annular coverage for lost circulationzones. It is generally believed that RCCPT helps minimize the circulationpressure and hence, allows cement placement with no apparent losses.
A basic hydraulic design study is conducted to determine the anticipatedpressure losses during the cement jobs run by using both the RCCPT and theconventional cement circulation placement technique (CCCPT).
Results have shown that, for each design case (i.e., wellbore geometry andthe rheology of cement slurry), there is a critical depth above which theequivalent circulating pressure (ECD) with RCCPT can be higher than ECD with CCCPT. Examples of typical cement job design calculations are provided toillustrate the changing ECDs as a function of depth during both RCCPT and CCCPT.

Introduction
Lost circulation is one of the most common problems encountered whencementing a well. The problem becomes increasingly critical, particularly whencementing fractured formations such as the ones encountered in geothermalwells, and coal bed methane wells, or low fracture gradient zones near sea bedsin offshore wells. Primary cementing of these zones using the conventionalcement circulation placement technique (CCCPT) has been very difficult, evenwith lightweight and foamed cement.
Reverse circulation of cement placement technique (RCCPT) has been offeredas an alternative to eliminate some of the problems experienced when cementingpotential lost circulation zones(1–5).
Marquarie and Brisac(1) reported successful applications of RCCPT in the North-Hassi-Messaoud Field in Algeria. Using RCCPT, they were able to cement aweak Triassic formation above the casing shoe without allowing the plasticclays (above the weak zone) to extrude and salt water to enter the well.
Griffith et al.(2) conducted large scale experimental tests to investigatethe advantages of RCCPT. They have suggested that RCCPT is a viable option tolower equivalent circulating densities during the cementing process. They havealso found that reverse circulation of cement on primary cementation neitherincreases nor decreases the displacement efficiency. Griffith et al.(2) alsooutlined a procedure for a typical reverse circulation cementing operationconducted by coal bed methane producers in the area of Trinidad, CO, in the U.S.
Best Method to Balance Torque Loadings on a Pumping Unit Gearbox
Authors: Rowlan O.L. , Mccoy J.N. , Podio A.L. 
Published: March 2010

Abstract
In general there are three methods available to the operator to determine the net torque loading on a pumping unit's gearbox. Two dynamic methods determine the instantaneous torque throughout the pumping cycle. Method 1 combines the measured surface dynamometer card and calculated torque factors with measured or calculated counterbalance moments from the crank and weights. Method 2 uses measured motor power with motor and drive efficiencies and the pumping unit speed to calculate gearbox torque. The third method combines the counterbalance effect (CBE) with the measured dynamometer loads and the torque factors to compute the net torque on the gearbox. The CBE test is a direct method of determining net gearbox torque at a specific crank position to estimate the maximum counterbalance moment. This static test is where the cranks and counterweights are held level until no upward or downward movement is noticed when the break is released. Field case studies applying all three methods to determining gearbox torque are presented in this paper. The pros and cons of using each method are discussed.

Introduction
The oldest and most common method of artificial lift used in producing oil wells is sucker rod pumping. In the United States and Canada, sucker rod lift is used in over 85% of artificial lift wells. The sucker rod lift system consists of four components:prime mover;pumping unit;counterbalance to the rod loading; and,sucker rods and associated downhole equipment. The function of the pumping unit is to convert the rotary motion of the prime mover to the vertical reciprocating motion of the polished rod. Therole of the prime mover is to furnish the necessary power to drive the system.
To improve efficiency, reduce the size of the prime mover and gearbox, and to load the gearbox more uniformly, the sucker rod pumping mechanism is furnished with some type of counterbalance system, where the counterbalance effect at the polished rod is approximately equal to the buoyant weight of the rods plus half the fluid load on the plunger.

Balanced or Unbalanced Gearbox Loading
For each complete stroke, the net torque load on the gearbox is cyclic, usually having two maximum peaks and two minimum valleys. The peaks occur during the upstroke and the downstroke, and the valleys occur at the top and bottom of the stroke. For balanced operation, the magnitude of the peaks should be approximately equal. Pumping unit manufacturers use various types of counterbalancing and mechanical features to reduce the peak gearbox torque and to smooth out the cyclic effects of the load.
The gearbox is said to be underbalanced or rod heavy if the upstroke peak is greater, whereas the gearbox is said to be overbalanced or weight heavy if the downstroke peak is greater. Since in a rotating system torque and power are directly related, the previous statements can be equally applied to the cyclic nature of the motor power developed during a complete stroke of the pumping unit.
Low Pressure SAGD Operations
Authors: Thimm H.F. 
Published: March 2010

Abstract
In the last few years, there has been increased interest in low pressure SAGD operations, in part, due to the gas over bitumen resource conflict. In an earlier paper, it was predicted that low reservoir steam pressures had the effect of sharply reducing hydrogen sulphide and carbon dioxide production per barrel of oil. Likewise, particularly troublesome scales, such as the magnesium and calcium silicates, were less thermodynamically favoured than at high steam pressures.
Further investigations into the fate of gases in SAGD have been undertaken, especially for the case where the virgin pressure of the reservoir is low. In such cases, the amount of solution gas is limited, and the bitumen at steam zone pressure is often undersaturated with respect to the available methane. The polar gases, hydrogen sulphide and carbon dioxide, on the other hand, are almost entirely produced via dissolution in the produced water. In the low virgin pressure case, the methane is entirely produced via dissolution in bitumen. This contrasts with initial reservoir pressures of, for example, 3,500 kPa, where more than half of the methane is also produced via the produced water. The other major difference is that, in the low virgin pressure case, very little gas is predicted to accumulate in the steam zone.
This paper examines the scaling tendencies of minerals, and the fate and compositions of produced gases in both low pressure SAGD and SAGD in low virgin pressure reservoirs. Use is made of recent advances in gas-liquid solution thermodynamics. The implications of this work include a possible effect on simulation studies for bitumen production, as well as on cap gas production via the produced water. This may also be an equity issue in the Athabasca area where cap gas has been shut in by regulatory intervention.

Introduction
There has been considerable interest in the issue of SAGD steam zone pressure (or temperature) in recent years. The issue revolves around the range of pressures under which a given SAGD project might be operated, without serious adverse economic effects on the project. Chhina(1) is reported to have advocated the use of lower pressures in order to reduce steam-oil ratios (SOR), and therefore production costs. The issue has been further explored by Kisman(2), who defines low pressure SAGD as involving "pressures below what steam/gas lift can accommodate, and above pressures where low-pressure consequences, such as reduced oil rates and artificial lift difficulties, affect the viability of SAGD operations." One of Kisman's conclusions was that operation at reasonably low pressures provides savings due to reduced SOR, and the smaller production well liners and tubulars that are needed. While there are limited field data on low pressure SAGD at present, the issue has received more detailed attention in the last few months owing to the ongoing gas-bitumen resource conflict.
A previous paper(3) explored a number of aspects of the engineering chemistry of SAGD, which are also dependent on the pressure (i.e., temperature) of the steam zone.
The Importance of Comprehensive Gas Field Surveillance
Authors: Baker Richard 
Published: March 2010

Abstract

Outline of Problem
Gas field surveillance historically has not been given the same priority as oil field surveillance because of a couple of significant stumbling blocks: first, the apparent simplicity of gas reservoirs- at least upon initial examination; and, second, the historically low commodity prices of gas relative to oil. The presumption that gasfield surveillance was easily derived from the knowledge that, in most gas pools, single phase flow existed, leading to the assumption that "tank like" behaviour was occurring. However, on examination of hundreds of gas pools, my viewpoint on that matter has changed dramatically. Of course, today's commodity prices are also changing both the relative and absolute perceptions about the economic importance of gas.
Initially, in the Western Canadian Sedimentary Basin (WCSB), industry encountered and dealt with very high quality gas resources, such as those found in Leduc reservoirs. These reservoirs had high permeability and were not compartmentalized; this naturally led to the "tank model" approach. These pools had behaviour as illustrated by Figure 1(a). In the last few years, we have moved from what I would term "Tier One" resources to lower quality ones, as shown in Figure 2.
Indeed, a large portion of reservoirs do not exhibit that "tank like" behaviour shown in Figure 1(a); instead, there is often a fairly large pressure gradient across pools and non-tank like behaviour, such as that shown in Figure 1(b). This paper stresses the importance of comprehensive surveillance for those types of fields, using simple methods of production analysis and pressure diagnostic tools.
There has been an explosion of research on using gas rate decline methods to characterize reservoirs with an effective permeability less than 0.1 mD (k &lt; 0.1mD). However, the transient gas rate decline and practical analysis of such low permeability gas reservoirs are not the focus of this paper. This paper instead focuses on gas field surveillance for multi-well pools in which wells are in boundary dominated flow.
The objectives of any gas surveillance program are relatively simple:What is the Original Gas in Place (OGIP)?;What is the current gas in place?;Where is the current gas in place located?;What is the permeability or capacity (kh) of the wells and pool?;What are the limiting considerations to gas recovery factor (low permeability, liquid lifting problems, low continuity, high back pressure, or water influx)?;What can be done to improve the rate of recovery and the recovery factor? and,Can this be done economically?
In order to understand the above questions, we must relate the static model (geological/petrophysical) to the dynamic (production/ pressure data) one.

Surveillance Methodology
The following work flow has proven to be useful in determining the true potential of gas reservoirs:Examine the production profile of individual wells and the field. Examine the initial production rates (IP), interference effects, types of decline, and decline rates (production diagnostics);
A New Technique to Measure the Breakthrough Capillary Pressure
Authors: Smith J.D. , Chatzis I. , Ioannidis M.A. 
Published: March 2010

Abstract
The breakthrough capillary pressure is an important macroscopic property of porous media that is used to predict permeability and to correlate capillary pressure curves. It is normally determined using the porous plate method, where the non-wetting phase is introduced into the medium in increasing steps of pressure until it establishes a continuous pathway through the sample. In mercury porosimetry, breakthrough capillary pressure is identified as the pressure corresponding to about 10 - 20% non-wetting phase saturation or the point of inflection in the drainage capillary pressure curve. A new method for measuring the breakthrough capillary pressure has been developed, involving a constant rate injection process as opposed to constant injection pressure. The scope of this paper is to report the accuracy and reliability of the new technique in measuring the breakthrough capillary pressure by reporting test results on transparent micromodels and Berea sandstone core samples. Air or mercury was used as the non-wetting phase while water (or brine, in the case of core samples) was the wetting phase. Constant rate injection was provided by means of a syringe pump, using water to displace a slug of either air or mercury in a tube connected to the porous medium at rates of about 1.8 × 10−2 cm3/min. Pressure was measured at the sample inlet using a pressure transducer and data were recorded using a data acquisition system. The injection pressure vs. time plot reveals the highest pressure established in such a test, which is identified as the breakthrough capillary pressure. It was concluded that the new test enables the determination of the breakthrough capillary pressure in micromodels with excellent accuracy. The new test was also validated using a sandstone core sample.

Introduction
In the literature of immiscible displacement in porous media, the terms "breakthrough capillary pressure," "threshold pressure," "entry pressure," and "bubbling pressure" are frequently encountered. It has been observed, for example, that in order to make a non-wetting phase, such as air, flow through a porous medium saturated with brine, the applied capillary pressure on the air side has to exceed a critical limiting value, Pc °, at which air can flow through the medium (i.e., can break through and emerge as bubbles from the outlet face of the sample). The pore channels in the medium used by the air to break through the sample are made up of pore sizes greater than or equal to the pore size De °, defined by
Equation (Available In Full Paper)
Where γ is the interfacial tension, θ is the contact angle, and De ° is the (equivalent) diameter of a capillary tube of circular cross-section which requires the same capillary pressure, Pc °, for penetration as that measured at breakthrough capillary pressure in the porous medium. The value of De ° calculated using Equation (1) is the minimum capillary size that is necessary for the non-wetting phase to invade and break through the medium.
Dual Gas Lift in Wells With Downhole Water Sink Completions
Authors: Marcano L. , Wojtanowicz A.K. 
Published: March 2010

Abstract
Downhole Water Sink (DWS) technology controls water coning in dual-completed wells by concurrently producing water from the bottom completion below the oil-water contact, and oil from another completion at the top of the oil sand. It has been shown that DWS improves well productivity, increases oil recovery, and could produce oil-free water for direct injection or overboard dumping offshore. To date, DWS has been applied in natural flow wells or wells where a downhole pump can be easily installed. However, in many areas, such as the Louisiana Gulf Coast and Venezuela where water coning is commonplace, the only production method is gas lift.
This paper presents a feasibility study and a design method for dual gas lifting in DWS wells. The design employs a two-tier nodal analysis for several combinations of two tubing strings- one for oil and a second one for water-installed in a production casing. First, nodal analysis is performed separately for the water and oil legs in order to define their operational range. Then, the two solutions are combined and coupled with the Inflow Performance Window (IPW) describing the operational domain (top inflow rate vs. bottom inflow rate) of the well.
Using the new method, a simulation study was conducted using data from actual wells. The results indicate that the gas lift would limit the performance of DWS wells. Moreover, the design can be optimized for maximum production of oil with controlled water withdrawal from the bottom completion. Limitations such as maximum gas injection rate, or injection gas pressure, are discussed. Also, this paper presents an example of a theoretical performance of a DWS well with gas lift.

Dual Gas Lift-State of the Art
Gas lift is a flexible method. It is possible to use it in wells of 0.159 m3 (a few barrels) per day, or wells of 159 m3 (a thousand barrels) per day. There are several methods of producing hydrocarbons using gas lift, but continuous gas lift is most common. Presently, there are at least 1,500 wells in Venezuela producing by intermittent gas lift. Also, single well completions are the most used gas lift installations around the world.
For any type of gas lift method, there is a maximum production rate, which is a function of depth, reservoir, completion, and surface conditions. This maximum production requires a specific optimized rate of gas injection. Any additional gas injection rate would result in an oil production rate smaller than the maximum rate.
To optimize gas lift for a given well, which includes the selection of tubing strings, size limitations, and maximum available gas flow rate, it is necessary to find the best depth of injection point and the gas injection pressure.
Although dual gas lift has been theoretically developed, it has not been practiced very much since single well completions are most commonly used around the world. In fact, only a few field cases of dual gas lift have been reported in the literature(1–8).