Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Southwest of the fairway, Fruitland coals are typically 20 to 40 ft thick and are considerably underpressured with vertical pressure gradients in some areas of less than 0.20 psi/ft. The low gradients are attributable to low permeabilities, low recharge rates along the southern rim of the basin, and hydraulic isolation from the fairway area.
Relative permeability curves in coalbed methane reservoirs (CBM), acquired by analysis of production data, can differ from laboratory-measured curves due to complications such as stress-desorption dependent permeability and cross-formational flow. This paper aims to derive relative permeability curves for coalbed methane reservoirs using production data analysis, as well as discuss curve characteristics and shapes. Field examples from the San Juan Basin in the US and the Qinshui and Ordos Basins in China are presented to provide a worldwide view of relative permeability curve shapes. These field examples are analysed using a tank type model, a common production data analysis tool, and the influential factors on curve shapes are discussed. The results and analysis indicate that permeability enhancement during the life of the well, and cross-formational flow between the coal seam and adjacent formations, can strongly control curve shapes. These effects, when not detected, can result in irregular relative permeability curve shapes obtained by analysis of production data. Direct measurement of permeability enhancement requires time-lapse production tests while investigation of cross-formational flow of water into coal seams requires hydraulic connectivity assessment, which are time consuming and expensive to conduct. The signatures of relative permeability curves presented in this study allow indirect determination of permeability enhancement and cross-formational flow in coal seam gas reservoirs.
The evidence from the produced-brine chemistry suggests that the Gyda field has experienced a variety of geochemical reactions caused by the high temperature and initial calcium (Ca) concentration, and so it is worth reviewing the produced-water data set and studying what in-situ geochemical reactions may be taking place.
Produced-brine-chemistry data from 16 wells in the Gyda field are plotted and analyzed in combination with general geological information and the reservoir description. A 1D reactive-transport model is developed to identify the possible geochemical reactions occurring within the reservoir triggered by seawater injection, and then extended with the inclusion of thermal modeling and also to be a 2D vertical-cross-section model.
Three possible classes of formation-water composition in different regions of the Gyda field have been identified by analysis of the produced-water data set. Anhydrite and barite precipitation are the two dominant mineral reactions taking place deep within the reservoir. Magnesium (Mg) stripping may be a result of multicomponent ion exchange (MIE), dolomite precipitation, or a combination of both. Reservoir temperature is lowered during coldwater injection. The solubility of anhydrite increases at lower temperature, and anhydrite will gradually dissolve in response to the movement of the temperature front, which is much slower than the formation/injection-water mixing front. The extent of mineral precipitation within the reservoir can be reduced by the heterogeneity; the modeling shows that the extent of ion stripping caused by mineral reactions in the reservoir is greatest when simulating a single uniform layer. Brine mixing and the occurrence of geochemical reactions caused by vertical mixing are not observable, even when assigning a high vertical permeability in a heterogeneous model.
Thermal modeling is included to evaluate the effect of nonisothermal processes and heat transport on the geochemical reactions, especially the anhydrite mineral reaction. We have investigated how the difference in horizontal permeability in the two layers affects brine mixing of formation and injection water and geochemical reactions.
Produced water was sampled and measured repeatedly during production from an offshore field, and an extensive brine-chemistry data set was developed. Systematic analysis of this data set enables an in-depth study of brine/brine and brine/rock interactions occurring in the reservoir, with the objective of improving the prediction and management of scale formation, along with improving its prevention and remediation.
A study of the individual-ion trends in the produced brine by use of the plot types developed for the reacting-ions toolkit (Ishkov et al. 2009) provides insights into the components that are involved in in-situ geochemical reactions as the brines are displaced through the reservoir, and how the precipitation and dissolution of minerals and the ion-exchange reactions occurring within the reservoir can be identified. This information is then used to better evaluate the scale risk at the production wells.
A thermodynamic prediction model is used to calculate the risk of scale precipitation in a series of individual produced-water samples, thus providing an evaluation of the actual scaling risk in these samples, rather than the usual theoretical estimate, on the basis of the endpoint formation- and injection-brine compositions and the erroneous assumption that no reactions in the reservoir impact the produced-water composition. Nonetheless, the usual effects of temperature, pressure, and brine composition are accounted for in these calculations by use of classical thermodynamics. The comparison of theoretical and actual results indicates that geochemical reactions taking place in this given reservoir lead to ion depletion, which greatly reduces the severity and potential for scale formation. However, ion-exchange reactions are also observed, and these too affect the scale risk and the effectiveness of scale inhibitors in preventing deposition.
Additionally, comprehensive analysis by use of a geochemical model is conducted to predict the evolution of the produced-brine compositions at the production wells and to test the assumptions about which in-situ reactions are occurring. A good match between the predictions from this geochemical model and the observed produced-brine compositions is obtained, suggesting that the key reactions included in the geochemical model are representative of actual field behavior. This helps to establish confidence that the model can be used as a predictive tool in this field.
The time and subsequent evolution of injection-water breakthrough are two of the main indicators monitored by production chemists. After injected water breaks through, the risk of scaling may change significantly, and scale-mitigation procedures should be planned accordingly. The fraction of the injection water in the produced brine may be ascertained only from analysis of the produced-water samples. However, to date, there has been little discussion about other applications of injection-water-fraction tracking. In this paper, new applications that follow on from accurate knowledge of injection-water fraction are proposed.
The calculated injection-water fraction may be applied
Strong evidence of the involvement of barium, sulfate, and magnesium ions in reactions, on the basis of the calculations of the relative ion deviations, has been shown for field data. In another case, application of injection-water fraction prompted a re-evaluation of formation-water compositions, and as a result, it was discovered that the well was producing from a different formation after reperforation.
The significant new developments presented in this paper allow analysts to obtain an indication of which ions are involved in the reactions, and the degree of relative ion deviations. Additionally, a technique is proposed that identifies the formation or formations from which the well is producing.
A vast body of conventional source rock analyses show that the Kimmeridge Clay Formation of the UK ( Draupne or Mandal formations of Norway and Farsund Formation of Denmark) contains large volumes of residual (i.e. unexpelled) oil where buried below about 3.2km. Free oil yields from both Rock-Eval pyrolysis and solvent extraction average at ~6 kg liquids/tonne rock with a range from 3 – 9 kg/tonne. Unlike most onshore basins where the source rocks are uplifted and hence generation has ceased, the North Sea, with rapid Tertiary-Recent sedimentation, offers the opportunity to drill directly into an actively generating world class oil-prone source rock. Prior knowledge locates sweet spots by selecting optimum maturity, thickness, organic richness and sedimentary facies (lithology) The pyrolysis and extract data quoted above equate to an average 140 bbls/acre.ft with a range of 70-210 bbls/acre.ft), the challenge being to extract it economically.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, 25-27 August 2014. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk.
Produced water was sampled and measured repeatedly during production from an offshore field, and an extensive brine chemistry dataset was developed. Systematic analysis of this dataset enables an in-depth study of brine/brine and brine/rock interactions occurring in the reservoir, with the objective of improving the prediction and management of scale formation, prevention and remediation. A study of the individual ion trends in the produced brine, using the types of plot developed for the Reacting Ions Toolkit (Ishkov et al., 2009), provides insights into what components are involved in in situ geochemical reactions as the brines are displaced through the reservoir, and how the precipitation and dissolution of minerals and the ion exchange reactions occurring within the reservoir can be identified. This information is then used to better evaluate the scale risk at the production wells. A thermodynamic prediction model is used to calculate the risk of scale precipitation in a series of individual produced water samples, thus providing an evaluation of the actual scaling risk in these samples, rather than the usual theoretical estimate based on endpoint formation and injection brine compositions, and the erroneous assumption that no reactions in the reservoir impact the produced water composition.
Understanding connectivity between injection and production wells is valuable information for reservoir management. Typically, connectivity might be evaluated using downhole pressure information or by injecting tracers into the reservoir. A less established but inexpensive technique is to history-match produced water compositions. For example, previous studies using this method have identified barriers to flow in reservoirs. Information on connectivity is also beneficial to scale management, and particularly where SO4-rich seawater is injected into reservoirs containing formation water rich in divalent cations (i.e. Ba, Sr, Ca) because in these cases the sulphate mineral scaling conditions in production wells are a function of the physical properties of the flow paths connecting the injection and production wells.
In this study, we have considered this latter relationship from a reverse perspective and explored the potential of history-matching produced water compositions to understand the physical properties of flow paths connecting injection and production wells for reservoirs under seawater flood. We have done this using a 1-D reactive transport model connecting an injector and a producer through a number of non-communicating layers characterized by permeability, porosity and height (completion interval). The model simulates the injection of seawater, its mixing with reservoir formation brine and the subsequent deposition of sulphate scales (barium and calcium sulphate among others) in the reservoir under equilibrium and kinetic conditions. The results of interest are the predicted produced water compositions over time from the model.
The model has been used to demonstrate how produced water compositions vary as the physical properties of the layers between the wells are modified and particularly how they vary in the presence of thief zones. Finally, a stochastic method was applied, in particular a Particle Swarm Optimisation algorithm, for the automatic history-matching of actual produced water compositions from individual wells in fields under seawater flooding. The results are promising and show that this technique can provide valuable information about the nature of inter-well connectivity.