The tank material balance (MB) equation for gas reservoirs has been written taking into account the effective compressibility of matrix and fractures.
The method has direct application on stress-sensitive naturally fractured reservoirs (nfr's). Under some conditions ignoring the effect of fracture compressibility (cf) can lead to over-estimating the volume of original gas in place using a cross-plot of p/z vs. Gp. The equation presented in this paper has been developed to overcome this weakness. The use of this MB is illustrated with an example.
It is concluded that fracture compressibility can play an important role in the calculation of gas in place in naturally fractured reservoirs.
The subject matter is significant because historically formation and water compressibilities have been neglected when carrying out MB calculations of conventional gas reservoir. This assumes that these compressibilities are negligible compared to gas. The assumption implies that the reservoir strata are static. When water influx is ignored, the assumption leads to a straight line in a cross-plot of p/z vs. cumulative gas production (Gp). However, this study shows that in those instances where fracture compressibility is large, the assumptions can lead to significant error.
Forecasting the performance of nfr's is a major challenge. Various authors have tackled the problem throughout the years using MB calculations. To the best of my knowledge, the effect of fracture compressibility has been usually ignored in MB equations for gas reservoirs. The work presented in this paper is not meant to replace a detailed reservoir simulation, which in my opinion is the best way to try to solve the problem, provided that reservoir characterization and quality of the pressure and production data is good. The idea is to have a tool that can provide a quick idea with respect to potential gas-in-place and recovery from stress-sensitive nfr's.
The conventional material balance for gas reservoirs leads to a straight line in a Cartesian cross-plot of p/z versus cumulative gas production, provided that (1) water influx is equal to zero, (2) the reservoir strata is static and (3) the water and formation compressibilities are negligible compared to gas compressibility. Although these assumptions are reasonable in many instances, there are cases the fractures are quite compressible. In these cases the conventional approach can leads to significant errors in the estimate of original gas in place. Similar problems have been observed in the past in geopressured reservoirs[1,2] and stress-sensitive naturally fractured oil reservoirs. Possible solutions have been proposed by Aguilera.[3,4]
This paper presents a MB equation that takes into account the effective compressibility of matrix and fractures. Stress-sensitive properties such as fracture porosity, fracture permeability and the portions of gas stored in matrix and fractures are taken into account.
In order to have a better understanding of the tools, techniques, and advantages involved in combining compression and plunger lift to deliquify low-rate gas wells, it is necessary to understand i) how liquid loading occurs and how it impacts well productivity, ii) how plunger lift is used to help deliquify low-rate gas wells, iii) how compression is used to deliquify low-rate gas wells, iv) the synergistic effects of combining plunger lift and compression, v) the operational challenges that arise when combining plunger lift and compression; and vi) the tools and technologies that can be applied, or are being developed, to enable compression and plunger lift to be combined in a cost-effective manner.
That is because downhole sampling of a gas/condensate fluid, unlike its oil counterpart, does not guarantee retrieval of single-phase fluid. The same is true for surface sampling because of incomplete surface and/or downhole separation. Given this reality, the PVT analysis of any fluid sample with an equation-of-state (EOS) model demands that the results are verified with independent measurements. Our analyses of many samples show that a good correspondence exists between the PVT-derived gradient and that obtained from wellbore-flow modeling of production-test data. Older generation formation testers, those prior to 1990, although yielding comparable results, had larger error bars owing to system limitations in repeatability of both pressure and depth measurements. We developed a yield-temperature correlation to fill in the information void for reservoirs that fall within the bounds of measured data over a large geographic area.
Field production in the Grand Valley gathering system varies minute by minute, creating a dynamic system that is difficult to model with standard practice. Using an innovative statistical method to handle the scale and complexity of the system, the model has consistently and accurately simulated the true flowing conditions of the system over the last five years. The model has been used to successfully locate and quantify substantial static and frictional pressure losses. As the field develops, proposed drilling programs are added to forecast the impact of the new wells on the system.
Paktinat, Javad (Universal Well Services Inc.) | Pinkhouse, Joseph Allen (Universal Well Services Inc.) | Williams, Curtis (Universal Well Services Inc.) | Clark, Gary Allen (Phillips Production) | Penny, Glenn S. (CESI Chemical)
The primary purpose of surfactants used in stimulating sandstone reservoirs is to reduce surface tension, contact angle and leakoff control. However, many of these chemicals adsorb rapidly within the first few inches of the sandstone formations, reducing their effectiveness in deeper penetration. This phenomenon causes surfactants to adsorb or plate-out reducing their effectiveness in post fracturing fluid recovery.
This study describes experimental and field case studies of various surfactants used in the oilfield. Several different surfactants including a nonionic ethoxylated linear alcohol, nonyl phenol ethoxylate, an amphoteric, a cationic and a microemulsion system were investigated to determine their adsorption properties when injected into a laboratory sand packed column. A laboratory simulated comparison study of commonly used surfactants and microemulsion was used to identify their leakoff and water recovery properties from gas wells.
Field data collected from Bradford, Balltown and Speechley sandstone formations confirmed experimental sand packed column and core flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional surfactant treatments. Wellhead pressures, flowing pressures and production data were collected and evaluated using a production simulator to show effective fracture lengths, damage surrounding the fractures and drainage areas with various fluid systems. These investigations and presented case studies can be used to minimize formation damage.
Copyright 2006, Society of Petroleum Engineers This paper was prepared for presentation at the 2006 SPE Gas Technology Symposium held in Calgary, Alberta, Canada, 15 17 May 2006. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted 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 an abstract of not more than 300 words; illustrations may not be copied.
Sour gas reservoirs with high content of sulfur are distributed widely around the world. Solid elemental sulfur which dissolves in the gas phase originally in the reservoir, may deposit when the thermodynamic conditions of the temperature, pressure or composition changes in the process of production. Deposition of solid elemental sulfur may block the pores in the formation and significantly affect the gas deliverability. In this paper, sulfur deposition mechanism is analyzed in the reservoirs. Based on the characteristics of sulfur deposition in the formation, a corrected function is introduced to modify the gas flow. Then, an evaluation method of the effect of sulfur deposition on gas deliverability is presented. For a practical sour gas reservoir, the gas deliverability considering sulfur deposition in formation is calculated and evaluated. The results show that the decrease degree of gas deliverability is different and it depends on the physical parameters in the formation on which the gas well is located.
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 Societ y of Petroleum Engineers and are subject to correction by the author(s). 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.
Several methods such as hydraulic fracturing and solvents have been proposed to restore production rates but all of these methods have limitations or they are only effective for short periods of time. We have evaluated new surfactants using a methanol-water mixture as the solvent to treat cores under reservoir conditions. The surfactants have been tested under reservoir conditions using a variety of cores and found to be promising since they significantly increased the steady state relative permeability. Experiments were performed to evaluate the effectiveness of these surfactants at high temperature and high gas flow rates over a range of capillary numbers on the order of those near production wells. The productivity index for sandstone cores was improved by a factor of 2 to 3 for temperatures over the temperature range of 145 to 275 F for the Novec FC 4430 polymeric surfactant in the methanolwater mixture.
In 1987, air hammers were tested on 27 wells in the Waterton, Jumping Pound, and Clearwater areas of Alberta, and in the Flathead valley of British Columbia.