Chen, Zhiming (State Key Laboratory of Petroleum Resources and Prospecting in China University of Petroleum, Beijing, and University of Texas at Austin) | Liao, Xinwei (State Key Laboratory of Petroleum Resources and Prospecting in China University of Petroleum, Beijing) | Zhao, Xiaoliang (State Key Laboratory of Petroleum Resources and Prospecting in China University of Petroleum, Beijing)
Forecasting coalbed-methane well performance in the Qinshui Basin is a key task for predicting future gas production, There is evidence suggesting that complex fracture geometry and multiple hydraulic-fracture networks might develop. Unfortunately, very limited work has been published on the production analysis of multiple-fractured vertical wells (MFVWs) in coalbed-methane reservoirs. To better understand the production performance of the MFVWs, a new, fast, and reliable methodology is presented in this paper. This semianalytical methodology is derived from an analytical reservoir solution and a numerical fracture solution. Dual-porosity, gas-diffusion, gas-adsorption, and stress-sensitivity effects are considered. Verification of the methodology is accomplished through comparison with synthetic-reservoir-simulation cases and with field-performance data. Good agreement is shown between results from the proposed methodology and those from a reservoir-simulation model. Results from this study indicate increasing transient-gas-production rate and cumulative gas recovery with increasing natural-fracture permeability, gas-storage coefficient, Langmuir volume, fracture conductivity, and fracture length. The transient gas-production rate and cumulative gas recovery were found to decrease with increasing stress-sensitivity coefficient. The parameters found to have the strongest and weakest effects on the gas-production rate were the nature-fracture permeability and the fracture conductivity, respectively. Results from this study on MFVWs in coalbed-methane reservoirs indicate fracture length is more important than fracture conductivity in terms of its effect on gas productivity.
To develop scale management strategies and plans during field development planning, it is important to know the composition of formation water in the reservoir. Typically, formation water samples will be collected from appraisal wells and analysed for this purpose. However, when the wells are drilled with water-based mud, the samples are often contaminated with mud filtrate that has invaded the formation during drilling. By adding a tracer to the drilling mud and using a simple mass balance correction technique, it is possible to correct for the effects of contamination and obtain an estimate of the formation water composition. But, where reactions occur during invasion or within the sample after collection, this method of correction will generate an erroneous estimate of the composition. The errors will increase with the extent of reaction and degree of contamination.
In this paper, we describe a new ‘correction’ approach which additionally makes use of (a) 1-D reactive transport modelling of mud filtrate invasion and (b) modelling of reactions occurring in formation water samples after collection. This approach accounts for the potential effects of these reactions and provides an estimate of the formation water composition within uncertainty limits. It reduces the risk of obtaining erroneous estimates of formation water composition and is particularly beneficial where reactions occur and where the mud contamination fractions are elevated (e.g. ~10-40%). At higher fractions, the uncertainties can be so high that the estimated compositions are not useful, emphasising the risks of trying to estimate formation water compositions from heavily contaminated samples.
This approach has been applied to formation water samples obtained from the Nova Field (formerly Skarfjell, Norwegian North Sea). It has meant that the resulting composition and associated uncertainties have been used with more confidence in scale management planning; to select seawater as the injection water, and to identify the scale risks across the relevant nodes in the production process over the life of field of the asset. Based on these risks, appropriate scale mitigation and monitoring measures have been selected.
The deposition of carbonate and sulphate scales is a major problem during oil and gas production. Managing scale with chemical application methods involving either scale prevention and/or removal are the preferred methods of maintaining well production. However, chemical scale control is not always an option, depending upon the nature of the reservoir and well completion and, in cases of severe scaling, the problem can render chemical treatments uneconomic unless other non-chemical methods are utilised.
A variety of non-chemical scale control methods exist, the most common being injection of low salinity brines or low sulphate seawater (LSSW) using reverse osmosis and a sulphate removal plant (SRP) respectively. In addition, careful mixing of lift gas, produced waters and reinjection, coatings, smart well completions with active inflow control devices (ICD) and sliding sleeves (SS) are other methods.
All of these techniques, including combinations thereof, are currently in use and the advantages and disadvantages of the key techniques are compared to chemical methods for both carbonate and sulphate scale control. A detailed example from a North Sea field demonstrates where downhole chemical scale control has not been required through a strategy of careful mixing of lift gas, brines and produced water re-injection. This was combined with understanding fluid flow paths in the reservoir and their likely breakthrough at production wells.
Consideration is given to the injection of smart brines to scale deep in the reservoir, and data from North Sea chalk fields shows how "
This paper presents a comprehensive review of non-chemical methods for downhole scale control and discusses how the use of these techniques can provide alternative scale management strategies through minimising or alleviating the need for downhole chemical treatments.
Formation of sulphate and carbonate scale is well understood within the hydrocarbon extraction industry with injection of incompatible water such as seawater into reservoir with significant concentration of barium, strontium and calcium. To overcome this challenge chemical inhibition has been utilized for many decades and in the past 15 years elimination/reduction of the sulphate ion source from injection seawater using sulphate reduction membranes has been employed. This paper present laboratory work to qualify a scale inhibitor and field results of its application to prevent scale formation when an operator had to change from low sulphate seawater (LSSW) mixed with produced water (PW) for their water injection source to a blend of LSSW/PW and full sulphate seawater (SW). The increased level of sulphate presented a significant scale risk within the topside process on fluid mixing but more significantly increased the risk of scale formation within the near wellbore region of the injector wells which were under matrix injection rather than fracture flow regime. The qualification of a suitable inhibitor required assessment of the retention of a potentially suitable vinyl sulphonate co polymer scale inhibitors to ensure it had low adsorption and was able to propagate deep into the formation before being adsorbed from the supersaturated brine. Coreflood studies using reservoir core were carried out to assess the scale risk of the LSSW/PW/SW brine, propagation and release characteristic of the short-listed scale inhibitors. The recommendation that followed the laboratory studies was to apply a batch treatment of concentrated scale inhibitor to each injector well to provide a high concentration pad of scale inhibitor that would be transported into the reservoir when the scaling LSSW/PW/SW fluid was injected. Protection was provided by continuous application of the same chemical at minimum inhibitor concentration to prevent scale formation within the topside and the desorption of the batched inhibitor within the near wellbore would prevent scale formation within this critical region. Thirteen injection wells were treated with a pad of 10% vinyl sulphonate co polymer scale inhibitor to a radial distance of 3 ft.
Injection of sea water (SW) into oil reservoirs for pressure maintenance or sweep can in some cases cause reservoir souring, sulphate scaling and formation damage. Change of injection water from SW to desulphated sea water (D-SW) may reduce these problems. The objective for the presented study was to investigate the interactions between reservoir chalk rocks and D-SW, and to determine the effects of low sulphate concentration in formation water (FW) on oil production from reservoir chalk.
FW, SW, D-SW (synthetic) and water from a sulphate removal plant (SRPW) were injected to reservoir chalk plugs. Effluent samples were analysed for sulphate, pH and elements to investigate the interactions between brines and minerals. During the brine injections, the potential for formation damage was also evaluated by measuring differential pressure across the core plugs. Reservoir chalk plugs were prepared using FW without sulphate and FW with sulphate concentration as in real FW, to investigate the effect of initial sulphate on spontaneous imbibition and viscous flooding.
No pressure build-up was observed when FW, SW, D-SW and SRPW were injected to the reservoir chalk plugs. Sulphate effluent peaks were observed during injection of FW, D-SW and SRPW to the reservoir chalk. The effluent pH was higher in the D-SW and SRPW injections than in the FW injections. The compositions of effluent samples confirmed the interactions between the reservoir chalk and these brines. Both spontaneous imbibition and viscous flooding with SW showed that the reservoir chalk with initial sulphate was more water-wet than the same chalk without initial sulphate.
Injection of D-SW will reduce the amount of sulphate produced in the oil fields, but the study has shown that sulphate will be produced due to the release of sulphate from the original reservoir chalks. Since SW has been reported to improve the oil recovery, it is important to compare the oil recovery potential for D-SW and SW before the type of injection brine is selected. It will then be important to prepare the reservoir rock with the correct amount of initial sulphate.
Reservoir model is widely used in oil and gas industry for hydrocarbon resources assessment, development, and management with different depletion strategies. The reservoir model is built through integration of multi-disciplinary information, data and interpretation at various scales. Integration of data from various resolutions and scales is usually a big challenge in constructing reservoir model due to its impact to the model's ability to make a reliable production forecast. The objective of this study is to analyze the impact of scale changes in clastic reservoir modelling and to evaluate its implication to hydrocarbon volume in-place and fluid flow behavior. Several examples from clastic reservoirs of different geological environments were evaluated and data from various scale were incorporated in reservoir description in constructing a representative reservoir models. Reconciliation of various reservoirs properties using database such as core data, logs, DST and production/pressure were performed.
Permeability upscaling was observed posing significant challenges compared to the other properties at each stage. Therefore, the paper puts more emphasize on permeability while briefly discuss the other properties. Other challenges including complex reservoir types such as thinly laminated reservoirs are also evaluated. The study demonstrates that different permeability modeling methods may give significant impact on the hydrocarbon in-place and fluid flow characteristic. In the absent of production data to verify the in-place, the uncertainty of in-place is inevitable. In addition to that, those different permeability models may also give different flow characteristic.
It is concluded that by recognizing the scale difference and impact of averaging/upscaling with the guidance from production/pressure performance, robust reservoir model with representative reservoir properties could be achieved. This paper shares the best practices in integrating data from various scale/discipline and highlights the impact of the data integration at right scale in constructing robust reservoir model.
Hu, Yisheng (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Mackay, Eric (Heriot-Watt University) | Vazquez, Oscar (Heriot Watt University ) | Ishkov, Oleg (Heriot-Watt University)
In waterflooded reservoirs under active scale management, produced-water samples are routinely collected and analyzed, yielding information on the evolving variations in chemical composition. These produced-water chemical-composition data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale-management programs designed to minimize damage and enable improved recovery.
In this interdisciplinary paper, the analyses of produced-water compositional data from the Miller Field are presented to investigate possible geochemical reactions taking place within the reservoir. The 1D and 2D theoretical model has been developed to test the modeling of barium sulfate precipitation implemented in the streamline simulator FrontSim. A completely 3D streamline simulation study for the Miller Field is presented to evaluate brine flow and mixing processes occurring in the reservoir by use of an available history-matched streamline reservoir-simulation model integrated with produced-water chemical data. Conservative natural tracers were added to the modeled injection water (IW), and then the displacement of IW and the behaviors of the produced water in two given production wells were studied further. In addition, the connectivity between producers and injectors was investigated on the basis of the comparison of production behavior calculated by the reservoir model with produced-water chemical data. Finally, a simplified model of barite-scale precipitation was included in the streamline simulation, and the calculation results with and without considering barite precipitation were compared with the observed produced-water chemical data. The streamline simulation model assumes scale deposition is possible everywhere in the formation, whereas, in reality, the near-production-well zones were generally protected by squeezed scale inhibitor, and, thus, the discrepancies between modeled and observed barium concentrations at these two given wells diagnose the effectiveness of the chemical treatments to prevent scale formation.
A technical-economic research was done evaluating microfiltration polymeric membranes and cartridge filters as pretreatment of Sulfate Removal Units (SRU). These units were installed in a Stationary Production Unit (SPU) to reduce the concentration of sulfate from seawater (injection water in Enhanced Oil Recovery). The use of seawater with low sulfate in enhanced oil recovery reduces the risk of sulfate deposits during the oil production. Ten companies from different nationalities involved in the industrial water treatment and manufacturing of polymeric membranes sector, have contributed to this comparative research (only a preliminary stage of the future study with qualitative and quantitative analyses). This paper shows that polymeric microfiltration is more advantageous because reduce operational costs and microbiological contamination resulting in a lower risk of biofouling. It also improves the quality of treated water, increases the operational stability and availability of the injection water, extending the lifetime of the nanofiltration polymeric membranes.