Gas-water interface rise during early exploitation tests in alfina geothermal field (Northern Latium, Italy)

Alfina geothermal field is made up of a gas-cap (CO₂) overlying an almost closed aquifer. The wells drilled in the highest part of the reservoir produce gas while the others either produce hot water or are sterile.During the first production tests the analysis of pressure and water-levels showed that the gas-water interface had risen. This was later confirmed when a gas-producing well began carrying water.This paper attempts to explain field behaviour by means of simple calculations and assuming an idealized geological structure.This study gives an estimation of the average porosity and initial gas in place.     

Thermodynamic behaviour of the Bagnore geothermal field

In 1959 production began from the Bagnore reservoir near the Mt. Amiata Volcano. The reservoir gas was initially at a pressure of approximately 23 ata. Its noncondensable gas content was more than 80% by weight, most of which was CO₂. During the first few years of production the noncondensable gas content and the reservoir pressure dropped simultaneously to about 10% by weight and 7 ata respectively. They have been changing very slowly since that time.Detailed studies of hydrogeological data from the Bagnore field were made as a part of this work. The initial reservoir temperature was estimated to be between 170 and 180°C. The history of watering-out of individual wells on the periphery of the field was examined. The depth of fractures in these wells can be correlated with the gas-water interface in the reservoir which is assumed to rise in direct proportion to the drop in reservoir pressure.A mathematical model which accounts for thermodynamic and chemical equilibria between the vapor, liquid and solid carbonate phases in the reservoir was developed and applied to a study of the initial conditions in the reservoir. A lumped-parameter model of a 2-phase, 2-component system was then developed. This CO₂-H₂O, liquid-vapor model was used to calculate history of pressure and composition for the reservoir. These calculated histories compared favourably with those observed in the field.This research confirms the hypothesis that there was initially a large accumulation of noncondensable gas in the reservoir, and that it was drawn off during the first years of exploitation. Model calculations for the initial state of the reservoir indicate the CO₂ initially present could not be derived solely from local carbonate rocks. Calculations with the producing-state lumped-parameter model, furthermore, indicate that the long-term producing concentration of CO₂ cannot be accounted for by assuming reasonable amounts of CO₂-saturated liquid-water influx into the reservoir. These results point out that further investigation into the nature of CO₂ and water influx into the reservoir are required.     

Chemical changes in natural features and well discharges in response to production at Wairakei,New Zealand

Development of the Wairakei geothermal resource has resulted in changes to the chemistry of the discharged fluids. The output of hot chloride springs declined rapidly and eventually ceased 10 years after the commencement of drilling. Deep pressures were drawn down by well discharge resulting in an increase in size and pressure of the shallow steam zone. Natural heat flow in the Karapiti Thermal Area increased from 40 MWt in 1950 to 420 MWt in 1964. Reduced reservoir pressures have also caused cool and less-mineralised water to enter the Western Borefield production reservoir. This reduced the average chloride concentration in the well discharges from 1580 g/t in 1960 to 1230 g/t in 2001. By this time 34% of the well discharge was from cool inflowing water and this has decreased to 27% in 2004. Since the mid-1980s production at Wairakei has been increasingly supported by fluid extracted from the Te Mihi sector. “Dry” steam wells, with gas concentrations up to 3.2 wt%, were brought into service in 1989, and in the last decade production has been added from deep liquid wells. By October 2007 the total gas flow to the Wairakei and Poihipi Power Stations was 9500 kg/h. Temperatures (∼250 °C) and compositions of the deep Te Mihi wells are close to the inferred initial reservoir conditions. The commencement of injection in 1995 and an increase in shallow groundwater drainage have increased concentrations of calcium and CO₂ in total discharge. This has resulted for the first time in problems of calcite scaling in some wells although chemical evidence of injection returns is inconclusive.     

Evaluation of effective parameters on CO2 injection process in a gas condensate reservoir: A case study

One of the key problems in gas condensate reservoirs is condensate blockage phenomena or condensate banking that reduces the condensate recovery. This phenomenon occurs when by reservoir depletion the reservoir pressure declines below the dew point pressure. One of the most important and common methods to prevent condensate blockage is gas cycling. Nowadays, regarding the value of natural gas, the use of other gases such as CO₂ as a suitable replacement has increased. The purpose of this study is to evaluate different parameters such as injection rate, injection pressure, and the number of wells in CO₂ injection process, in order to determine optimum conditions for CO₂ injection with the maximum condensate recovery and minimum economic cost. The two-parameter, Peng–Robinson equation of state (EOS) was used to match PVT experimental data. Then various scenarios of CO₂ injection with different conditions have been studied, and optimum conditions for CO₂ injection were compared with the natural depletion scenario. The results showed that the injection rate and pressure play important roles in determining the best condensate recovery.     

An Investigation of WAG Process Using Horizontal Wells

In this study, a comprehensive laboratory investigation was conducted for the recovery of heavy oil from a three-dimensional (3-D) physical model, packed with 18°API gravity crude oil, brine and crushed limestone. A total of 15 experiments were conducted using the 3-D physical model with 30 cm × 30 cm × 6 cm dimensions. Basically, water-alternating gas (WAG) process was used for recovering heavy oil. Three groups of well configurations were mainly used: (i) vertical injection and vertical production wells, (ii) vertical injection and horizontal production wells, and (iii) horizontal injection and horizontal production wells. Base experiments were run with water only and carbondioxide alone and optimum rates for WAG process were determined. In CO₂ injection experiments, vertical injection and horizontal production well configuration supplied a higher recovery (15.06% OOIP) than that of the others. Horizontal injection and horizontal production well configuration gave poor recovery with the same gas rate, while vertical injection and vertical production was better off with a lower gas rate. The volumetric ratio of the water and CO₂ slugs (WAG ratio) was varied 1:3 to 1:10 in order to determine optimum conditions. For water alternating gas injection case at a WAG ratio 1:7, vertical injection and vertical production well configuration gave the highest recovery (21.04% OOIP). Waterflooding reached the best recovery (37.20% OOIP) in vertical injection and vertical production well configuration. Oil production from WAG injection is higher than that obtained from the injection of continuous CO₂ or waterflooding alone.     

The effect of capillary-trapped CO2 on oil recovery and CO2 sequestration during the WAG process

This study investigated capillary-trapped CO₂ depending on the consideration of hysteresis effect in relative permeability for various water-alternation-gas (WAG) operating conditions to ascertain the oil production process. From the simulation results of CO₂ WAG flooding method, the trapped CO₂ led to prevent water-flow, in which CO₂ acts as a gas blocker near the well. It caused the injection pressure increase during water injection period. As the trapped CO₂ in pores increased, the reservoir pressure was also increased and maintained above minimum miscibility pressure (MMP). Ultimately, it was concluded that the reservoir was kept under miscible conditions throughout WAG process, reducing residual oil and increasing oil recovery.     

Geochemical monitoring of the Krafla and Námafjall geothermal areas, N-Iceland

The Krafla and Námafjall high-temperature geothermal areas in N-Iceland have been exploited for steam production since the late and early 1970s, respectively. Power generation at Krafla was 30 MW until 1998, when it was increased to 60 MW. At Námafjall the steam has been utilized for operating a 3 MW back-pressure turbine unit, drying of diatomaceous earth and heating of fresh water for space heating. A total of 34 wells have been drilled at Krafla, of which 18 are producing at present. At Námafjall 12 wells have been drilled but only three are productive. The highest temperatures recorded downhole are 320 and 350 °C at Námafjall and Krafla, respectively. Geochemical monitoring in the two fields during the last 20–25 years has revealed decreases in the Cl concentrations in the water discharged from most of the wells that have been producing for more than 10 years. The cause is enhanced colder water recharge into the producing aquifers of these wells due to depressurization by fluid withdrawal from the geothermal reservoir. Such recharge is particularly pronounced in the central part of the Leirbotnar wellfield at Krafla but it is also extensive in the only producing well in the Hvíthólar wellfield. At Námafjall incursion of cold groundwater into the reservoir was particularly intense subsequent to the volcanic-rifting event in the area in 1977. Solute (quartz, Na/K, Na/K/Ca) geothermometry temperatures have decreased significantly in those wells where Cl concentrations have decreased but only to a limited extent in those wells which have remained constant in Cl. This indicates that the changes in the concentrations of the reactive components, on which these geothermometers are based, is largely the consequence of colder water recharge and not partial re-equilibration in the depressurization zone around wells where cooling of the fluid occurs in response to extensive boiling. Aqueous SO₄ concentrations increase as Cl concentrations decrease. Except for the hottest wells, which are low in SO₄, sulphate concentrations are controlled by anhydrite solubility. Increase in SO₄ concentrations is a reflection of cooling as anhydrite has retrograde solubility with respect to temperature. H₂S-temperatures are similar to the solute geothermometry temperatures for wells with a single feed. They are, on the other hand, higher, for wells with multiple feeds, if the feed zones have significantly different temperatures. H₂-temperatures are anomalously high for most wells due to the presence of equilibrium steam in the producing aquifers. The equilibrium steam fraction amounts to 0–2.2% by wt. of the aquifer fluid (0–47% by volume). CO₂ temperatures are anomalously high for some Krafla wells due to high flux of CO₂ from the magma intruded into the roots of the geothermal system during the 1975–1984 volcanic-rifting episode. During the early phase of this episode the Leirbotnar wells were the ones most affected. The new magma gas flux has migrated eastwards with time. Today some wells in the Sudurhlídar wellfield are the ones most affected whereas the Leirbotnar wells have recovered partly or fully. The depth level of producing aquifers in individual wells at Krafla and Námafjall has been evaluated by combining data on temperature and pressure logging and geothermometry results. The majority of wells at Krafla receive fluid from a single aquifer, or from 2–3 aquifers having similar temperature. The same applies to two of the three productive wells at Námafjall.     

Numerical simulation of a supercritical CO2 geothermosiphon

The thermo-hydraulic performance of a CO₂ geothermosiphon has been numerically investigated using the commercially available software CFX. A simple Engineered (or Enhanced) Geothermal System, EGS, consisting of an injection and a production well as well as a reservoir is numerically simulated. Both water and carbon dioxide have been examined as the working fluid. While the former fluid has been very popular for its availability, the latter offers advantages such as favorable thermodynamic properties as well as the inherent possibility of geosequestration. However, detailed analysis of such CO₂ geothermosiphon systems is not available in the open literature. Higher heat extraction rate from the reservoir at lower pressure drops for a CO₂ geothermosiphon, compared to water-based systems, can be achieved and general criteria for that are presented.     

Immiscible CO2 Flooding through Horizontal Wells

Abstract

The CO₂ immiscible process is a potentially viable method of enhanced oil recovery (EOR) for heavy oil reservoirs. In an immiscible CO₂ process, part of the injected CO₂ is absorbed into the reservoir fluids and part forms a free-gas phase in the reservoir. Three groups of well configurations were mainly used: (1) vertical injection and vertical production wells, (2) vertical injection and horizontal production wells, and (3) horizontal injection and horizontal production wells. In immiscible CO₂ injection, highest recovery was obtained by vertical injection-horizontal production (VI-HP), followed by vertical injection-vertical production (VI-VP), and the least by horizontal injection-horizontal production (HI-HP). In VI-HP well configuration, the best recovery was obtained as 15.1% OOIP. In continuous CO₂ injection experiments, oil recovery for the VI-HP well configuration was higher than that of the other well configurations. The lowest ultimate recovery was obtained from HI-HP well configuration. The distance between the horizontal injector and horizontal producer was another important factor for the displacement of oil. In all runs, CO₂ breakthrough occurred very early, showing the dominance of viscous forces and relatively small effect of mass transfer between CO₂ and oil. The total oil recovery varied considerably because of the differences in injection rates and because of the unstable displacement. As a whole, oil recovery increased with an increase in the injection rate of CO₂. The cumulative gas-oil ratio (GOR) appeared to be sensitive to the gas injection rate for all well configurations. An increase in oil recovery with injection rate during initial stages of the runs was affected by the cumulative GOR.     

A study on development effect of horizontal well with SRV in unconventional tight oil reservoir

Unconventional tight oil and gas are the main body of the increase of reserve and production in Ordos Basin. Based on the tight oil reservoir in Ordos Basin, a 7 point pattern well group numerical mechanism model with a multi-stage and multi-cluster horizontal production well in the middle and 6 vertical injection wells on the edge is established. PR3 equation of state model is used in the numerical model. The stimulated reservoir volume of horizontal well is realized by local grid refinement, and the wire-mesh model is used to simulation hydraulic fracture network. Application of the model, the development effect factors of tight oil reservoir are analyzed, which contain development methods (depletion development, water flooding development and CO₂ flooding development), reservoir permeability, SRV size, fracture density, fracture conductivity and cluster spacing. The results of this paper can offer suggestions to fractured horizontal well design and tight oil reservoir development.     

Methodology for calculating steam quality in geothermal reservoirs

A promising technique is presented for computing steam fraction in a two-phase reservoir, utilizing fluid composition and its variations. The molar fractions in the steam phase of the chemical species in the reservoir are first computed, starting with fluid composition at the wellhead. The gas species in the reservoir are partly in the vapour phase and partly dissolved in the liquid phase. We assume that the main gas species, such as CO₂, CH₄, H₂, H₂S and H₂O, are in chemical equilibrium in the reservoir. One other fundamental assumption is that the two-phase fluid is in phase and chemical equilibrium in the reservoir and fluid is transferred at the wellhead without any mass gain or loss, although phase changes may occur.     

Simulation of key parameters in CO2 injection for enhanced coalbed methane recovery in a deep well group

The use of CO₂-ECBM technology in deep coalbeds, by taking advantage of high CO₂ absorptivity, can displace more CH₄ as well as keeping long-term sequestration of carbon dioxide in large quantities. Our experiments in the block of northern Shizhuang show that the coalbed has an adsorption capacity for CO₂ which is two times of that for CH₄. With the pressure dropping, CH₄ (desorbs) more quickly than CO₂, and can be displaced effectively. Changes in reservoir physical properties caused by CO₂ injection mainly lie in permeability variations on account of matrix shrinkage and swelling during CO₂ adsorption and desorption. Usually, the permeability declines at first and increases rapidly as the reservoir pressure drops. Based on such variation patterns, geological and numerical models are established to analyze the influence of volumes, frequencies and modes of CO₂ injection on both methane production and recovery, as well as on CO₂ burying potentials, of both the well group and single wells. The modeling result shows that the gas recovery increases after 2-year CO₂ injection in the mode of 90-day injection, at a rate of 10–15 t/d, plus 90-day shut-in. Field tests indicate that the CO₂ adsorption capacity of the No. 3 coalbed is 8 t/d while the burying potential of the whole well group is about 12616t.     

The use of gas chemistry to evaluate boiling processes and initial steam fractions in geothermal reservoirs with an example from the olkaria field, Kenya

A method has been developed to evaluate boiling processes in the producing aquifer of “high-enthalpy” geothermal wells using data on the concentrations of CO₂, H₂S and H₂ in steam discharged. The extent to which water and steam are separated in the producing aquifer is evaluated as well as the amount of enhanced evaporation due to heat flow from the rock to the boiling water. Further, the initial steam fraction in the reservoir fluid is calculated. Results are presented for the Olkaria geothermal field, Kenya, to demonstrate the use of our method. They show that the initial steam fraction in the reservoir is very small: up to 0.25% of the mass, or about 10% by volume. Segregation of water and steam in the producing aquifers is rather extensive for some of the wells. Thus, water which has boiled and yielded steam into wells amounts to more than two times the mass of the fluid discharged from the well. The larger part of the exploited steam ( ) is generated by flow of heat from the rock to the boiling water.     

CO2 distribution in the atmosphere and noise survey after blow-out in alfina 1 well, Northern Latium, Italy

A water-dominated geothermal reservoir, with a gas cap (mainly CO₂) on the reservoir roof, was individualed in Torre Alfina zone, northern Latium, about 30 km south-east of Monte Amiata.The first exploratory well (Alfina 1), drilled in 1973, blew-out spontaneously so that no production casing could be inserted.After well shut-in several surface gas manifestations appeared which were considered of some risk to the environment.This paper describes the methods used to determine the degree of pollution and the total area involved.The study of the gas dispersion in the atmosphere, the noise resulting from production, and the meteorological conditions in the area, was used in drawing up a disposal plant project; this plant will be assembled on future wells as a safety measure where large quantities of fluids are involved.     

The solubility of Ni in molten Li2CO3–Na2CO3 (52/48) in H2/H2O/CO2 atmosphere

In this work the solubility of a Ni–Al anode for MCFC has been studied at atmospheric pressure and two different temperatures using various gas compositions containing H₂/H₂O/CO₂. It is well known that nickel is dissolved at cathode conditions in an MCFC. However, the results in this study show that nickel can be dissolved also at the anode, indicating that the solubility increases with increasing CO₂ partial pressure of the inlet gas and decreasing with increasing temperature. This agrees with the results found by other authors concerning the solubility of NiO at cathode conditions. The dissolution of Ni into the melt can proceed in two ways, either by the reduction of water or by the reduction of carbon dioxide.     

pH and silica scaling control in geothermal field development

Due to the increase of amorphous silica solubility as significant silicate ion forms in the pH range 7 to 8.5, the potential for the deposition of silica scale during reticulation (pipeline transmission) of waste geothermal waters to disposal sites is dependent on steam separation temperature, silica concentration and the pH of the residual fluid. For low salinity geothermal fluids the latter is related to the composition of the fluid, particularly the concentration of carbon dioxide remaining after the removal of steam for power generation using conventional separators. In general terms the higher the gas content of the initial deep aquifer fluid, the higher will be the pH of the waste waters, so that in many fields, where reservoir temperatures fall in the range 250 to 280°C, careful choice of separation pressures to maximise gas removal and hence elevate the pH of residual waters may obviate the problems of silica deposition, or the need to install costly chemical treatments such as acid or alkali addition. In designing and operating separators or flash plants it is important to avoid carryover of steam (containing CO₂ and H₂S) into the water reticulation lines, where, after heat loss, condensation occurs with resultant lower pH and higher scaling potential. Where flash plants are designed to receive a mixture of the two-phase discharges from a number of wells, consideration of the pH of the residual water resulting from steam separation may provide design constraints on the reticulation network such that silica scaling potential is minimised or entirely avoided. The Wairakei and Broadlands (Ohaaki) fields are used as examples of these design considerations in relation to the reservoir chemistry of the field and possible changes during extensive exploitation.     

天然气水合物开发的水平井控水控砂完井研究进展

2020年第二次南海水合物试采证明水平井是实现产业化的重要途径,计划在2030年南海天然气水合物商业开发中补齐粤港澳大湾区天然气供给的短板。但我国海洋水合物甜点多赋存在高含水、边底水丰富的非成岩泥质粉砂储层,水平井开发过程中储层水（排液）易携泥砂（出砂）脊进突入井筒导致产量降低,水平井控水控砂完井是产业化的瓶颈问题之一。针对第二次水平井开发水合物出现的新问题,分析了海洋天然气水合物储层开发过程中的水平井非均衡排液出砂情况,总结了国内外水平井控水控砂实验、模拟和现场的进展,提出了水平井开采水合物控水控砂的难点及我国面临的挑战。分析结果表明,天然气水合物储层开发的水平井控水控砂与常规油气开发存在共性问题,也有其自身分解特点及其赋存的非成岩储层有关的特性问题。针对我国海域天然气水合物储层间各向异性明显、潜在的“四气合采”和“碳封存”,对水合物水平井控水控砂抽取和注入提出了具体的研究思路及建议,以期推动海洋天然气水合物产业化开发进程。     

应力敏感对川西气田低渗气藏渗流的影响研究

川西气田中浅层主力气藏平均有效渗透率大多小于0.1×10-3μm2,具有典型低渗致密气藏特征.对于低渗油气藏渗流过程中应力敏感的影响程度,目前在国内外还存在较大的争议:有学者认为低渗透储层存在着较强的应力敏感性;也有学者认为储层岩石越致密,其对应力的敏感程度越低.地层压力变化可以作为验证低渗气藏是否存在应力敏感的重要参数.川西气田多数气井需压裂投产,因此本文仅针对压裂气井建立产能方程,并进行优化,从而建立物质平衡与方程优化法.利用物质平衡与产能方程优化法对CX135井,新场沙溪庙组气藏以及马井蓬莱镇组气藏的部分气井地层压力进行分析,发现考虑应力敏感和不考虑应力敏感计算所得的地层压力、无阻流量很相近,误差在5％以内,这说明应力敏感对川西低渗气藏气体渗流的影响较小,在产能计算过程中可以忽略不计.