Appreciable liquid and gas reserves can be found in gas condensate reservoirs. During gas production from the gas condensate reservoirs, the bottom-hole pressure may drop below the dew point pressure. When this occurs, liquid condensate will start to drop out of gas phase and accumulate in the area close to the wellbore where the pressure drop will be maximum. The accumulation of condensate, and sometimes water, in the area around the wellbore will result in reduction in the gas permeability and hence loss of production of gas and liquid condensate. Several techniques have been used to mitigate the problem of condensate and liquid blockage (banking) in gas reservoirs. These methods include injection of low flash point solvents, wettability alteration surfactants, gas cycling and hydraulic fracturing. None of the state of the art is a panacea for the problem since each method has its own pros and cons.
In the current study, a novel chemical treatment formulation based on surface modified fluorinated silica nanoparticles (NP) was developed to mitigate the problem of condensate and water banking. The newly developed formulation is able to effectively alter the wettability of the rock surface from oil and/or water wetting to neutral wettability for both phases or to intermediate gas wet. The size distributions of the fluorinated silica nanoparticles were characterized by dynamic light scattering (DLS). The contact angle of water and decane on the new formulation-treated rock surfaces was measured to characterize wettability alteration of the treatment. Coreflood experiments were performed using outcrop samples and field gas condensate fluid composition under reservoir conditions (temperature is 300°F and pressure is 4000 psi).
To investigate the nanoparticle size effects, two batches of the fluorinated silica nanoparticles with average sizes of 135, 180 and 400 nm were synthesized. The contact angle measured of water and decane on the treated sandstone surface was found to be 120 and 51 degrees, respectively; indicating that the fluorinated nanoparticles were able to change the wettability of the rock surface to strongly non-water wetting and moderately decane wetting. Several coreflood experiments were performed to optimize the fluorinated nanoparticles concentration and the solvent package. It was revealed that only three pore volumes (PV) of a treatment formulation composed of 0.065 wt.% concentration of fluorinated nanoparticles in butanol were able to achieve 37% improvement for gas and liquid relative permeability.
The new fluorinated nanoparticle-based treatment reported herein was able to change the rock surface wettability to be non-wetting with liquids (both water and decane) or intermediate gas wetting effectively. More importantly, the treated surface was relatively long-lasting since the pressure drop after treatment was shown to be fluctuating around 33 to 36 psi (the same level after pumping 250 pore volumes of gas condensate mixture from our lab experiments under reservoir conditions.
Prediction of reservoir performance during water displacement process is a routine procedure for homogeneous reservoirs but complicated in heterogeneous reservoirs. The Stiles method has consequently been used over time in the industry for such reservoirs. This method, however, is evidently time consuming and tedious as the varying permeability values are reordered and lumped. This paper applies the Welge procedure to a stratified reservoir without reordering or lumping of permeability with the aim to ensure improved productivity by more proper planning, more efficient use of resources and determination of the economic viability of the project. This paper also seeks to formulate a procedure that can judiciously handle even larger sets of permeability values to produce more accurate result
A fractional flow equation was derived for any number of layers to generate a single fractional flow curve (FFC). Injection inflow into a layer was determined using the layer capacities and this facilitated calculation of times to breakthrough and times to attain a particular saturation after breakthrough. A formula was then derived to determine the oil produced at any instant. A software was designed for the entire procedure to ensure faster and more accurate predictions. Results showed that heterogeneities had no effect on the microscopic displacement and thus the fractional flow curve remained unchanged whether the reservoir was heterogeneous or not. Heterogeneities affected only the total flow in the distinct layers and thus times to attain specified average water saturations. The results of oil recovery obtained were compared to those obtained using the Stiles method to demonstrate that this method is faster without loss of accuracy.
Nor has it been the purpose of the discussion presented thus far to provide explicit formulas for predicting quantitatively the recoveries from specific reservoirs or for evaluating them as items for sale or purchase. It has been an aim of this work to provide an exposition of the physical principles underlying the behavior of oil reservoirs so as to permit an understanding of their performance when observed in practice and an anticipation of the broad features of their performance from the consideration of basic data gathered during their development.
The physical and thermodynamic properties of the fluids have mainly played the role of parameters affecting only the details of the performance. Condensate-producing reservoirs are unique in that it is the thermodynamic behavior of the petroleum fluids that is the controlling factor in their performance and economic evaluation. It is for this reason that they will be given here a separate treatment, although their dynamical aspects are controlled by the same basic laws of fluid flow through porous media' as govern the production of crude oil and natural gas.
With production from gas/condensate reservoirs, the flowing bottomhole pressure of the production well decreases. When the flowing bottomhole pressure decreases below the dewpoint, condensate accumulates near the wellbore region and forms a condensate bank. This results in loss of productivity of both gas and condensate, which becomes more serious in intermediate- and low-permeability gas/condensate reservoirs, where the condensate bank reduces both the gas permeability and the well productivity.
Several techniques have been used to mitigate this problem. These methods include:
Gas cycling aims to keep the reservoir pressure larger than the dewpoint pressure to reduce the condensation phenomena. The limited volumes of gas that can be recycled in the reservoir can hinder the application of this method. For an ideal gas-cycling process, the volume of the gas injected into the reservoir will be larger than the total gas that can be produced from such a reservoir. Other approaches are the drilling of horizontal wells and hydraulic fracturing, during which the pressure drop around the wellbore region is lowered to allow for a longer production time, with only single-phase gas flow to the wellbore. These approaches are costly because they require drilling rigs. Another technique is the use of solvents, which shows good treatment outcomes, but the durability is a questionable issue in these treatments. Moreover, wettability alteration needs to be approached very carefully so as to not cause permanent damage to the reservoir. The use of fluorinated polymers and surfactants dissolved in alcohol-based solvents for wettability-alterations treatments was reported in many studies.
Each method has its own advantages and disadvantages, and can be applied under certain conditions. This paper presents all of these methods, along with their advantages and disadvantages and description of some of their field applications and case studies.
For many years one of the primary natural gas exploration and production targets in East Texas and West Lousiana has been the Cotton Valley (CV) Sands and associated subsections. The advent of new and successful technology for drilling horizontal wells have increased the return on investment to advantageous levels for this play. The Cotton Valley is a very abrasive, consolidated Jurassic-Cretaceous sandstone. When non-aqueous fluids (NAF) or conventional water-based fluid (WBF) systems are used in horizontal wells in this formation, abrasiveness combined with directional tortuosity and horizontal lateral lengths cause rates of penetration (ROPs) to suffer while torque and drag values increase to the point where drilling cannot be continued. The utilization of a high-performance water-based fluid (HP-WBF) system proves vital in meeting interval objectives while remaining cost-effective and environmentally friendly.
Primary fluid objectives in horizontal wells are typically very similar: help to maximize ROP, decrease torque and drag, stabilize the wellbore, and enhance wellbore cleaning efficiency. In an effort to improve drilling fluid effectiveness while maintaining consistent ROPs and manageable torque and drag values a number of fluid additives have been field tested in the CV horizontal wells with the goal of decreasing frictional forces. Examples include refined oil, sulfonated asphalts, graphite, and fine beads. All of these additions yield varying, inconsistent results. Using a newly developed high-performance fluid system, ROPs increase 20-50% as torque values decrease 20-50% simultaneously. The results using this systems approach show consistency, repeatability, and have proven to be cost effective.
Key factors influencing the necessity of a carefully and custom designed drilling fluid are hole size, casing design, drill string, bottom hole assembly, bit selection, and drilling fluid properties. The combined components of the well design help identify tangible measures of success. Average daily ROP and on-bottom torque are two drilling parameters identified as key performance indicators. Therefore, over the course of a given length of time ROP, torque values and other properties are monitored and recorded. After compiling and analyzing this the effectiveness of a high-performance fluid system can be determined and subsequently quantified. A case history analysis of over 30 horizontal Cotton Valley wells utilizing a high-performance fluid provides the basis for demonstrating the advantages and therefore the cost effectiveness of using this new fluid technology.
Numerous technical publications were made in recent years on effectiveness of reservoir simulation modeling in developing a tight gas resource. These papers question applicability of existing numerical simulation methodologies to hydraulically fractured Unconventional reservoirs. The continuously changing behavior of dynamically active gas molecules from an extremely poor quality reservoir to a highly conductive fracture and subsequently to a wellbore have been known to create complex solutions which cannot be fully resolved by conventional reservoir simulators. In addition to this, the inability of the wells to show dynamic interference during early stages of the production stacks atop an uncertainty of connected gas volume and reservoir quality away from the wellbore. Consequently, the investment decisions on optimum well spacing, infill wells and well design are not made at the right time resulting in a lost opportunity.
This paper proposes a reservoir simulation work flow and strategy for Unconventional Gas reservoirs. The strategy outlines the need to systematically move from simple to complex modeling solutions while creating a learning loop. Early modeling efforts need to focus on single wells in small sector models to understand impact of various uncertainties on the range of outcomes. The workflow identifies the learning stage that allows a progression to the next stage of simulation i.e. bigger sector models. An example will be presented to show how a fast progression from sector to full field modelling cannegatively impact final investment decisions and the field development strategy. BP has successfully applied this framework in North America and this strategy has been outlined for Oman Unconventional Gas development in Block 61. An early focus on single well and small sector modeling has shown significant learnings that will be shared in the paper.
For interpretation and inversion of microseismic data it is important to understand, which properties of the reservoir rock control the occurrence of brittle rock failure and associated seismicity during hydraulic stimulation. This is especially important, when inverting for key properties like permeability and fracture conductivity. Although it became accepted that seismic events are triggered by fluid flow and resulting perturbation of the stress field, the magnitude of perturbations, capable of triggering failure in rocks, can be highly variable. Parts of the rock, which are unlikely to fracture, will act as flow barriers after termination of stimulation. We compare occurrence of microseismic events at the Cotton Valley gas field to elastic rock heterogeneity, obtained from sonic logs. Our observations suggest that heterogeneity of the rock formation controls the occurrence of brittle failure. In particular, we ob- serve that the density of events is increasing with Brittleness Index (BI) of the rock, which is defined as a combination of Young’s modulus and Poisson’s ratio. We evaluate the physical meaning of the BI and characterize the influence of elastic rock heterogeneity on the probability of rock failure. Our analysis is based on the computation of stress fluctuations caused by elastic heterogeneity of rocks. We find that stress changes necessary to open and reactivate fractures in rocks are strongly correlated to fluctuations of elastic moduli. A crucial factor for understanding seismicity in unconventional reservoirs is the role of anisotropy of rocks. We evaluate a VTI model corresponding to a shale gas reservoir in the Horn River Basin to understand the relation between stress, event occurrence and elastic heterogeneity in anisotropic rocks.
Ahn, Chong Hyun (Pennsylvania State University and U.S. Department of Energy NETL) | Chang, Oliver C. (Pennsylvania State University and U.S. Department of Energy NETL) | Dilmore, Robert (U.S. Department of Energy NETL) | Wang, John Yilin (Pennsylvania State University and U.S. Department of Energy NETL)
The most effective method for stimulating shale gas reservoirs is horizontal wells with successful multi-stage hydraulic fracture treatments. Recent fracture diagnostic technologies such as microseismic technology have shown that complex fracture networks are commonly created in the field. However, often times, the stimulated reservoir volume (SRV) obtained from the microseismic interpretation does not provide propped fracture volume and its conductivity such that, commonly, there is a difference between the SRV that is open for the gas flow and SRV obtained from microseismic diagnosis.
In this paper, the coupled hydraulic fracturing model that is capable to simulate dynamic fracture propagation, reservoir flow simulation, the interactions between hydraulic fractures and pre-existing natural fractures, and proppant transportation will be used to conduct numerical experiments. The effects of proppant size, horizontal differential stress, fracture fluid viscosity, pumping rate, and natural fracture spacing on the propped stimulated reservoir volume (PSRV) and hydraulic fracture conductivities is then compared and quantified. At last, using the knowledge gathered during parametric studies will be applied to enhance the effectiveness of stimulation.
Simulation results from the parametric studies show that enlarging SRV does not guarantee larger PSRV. Our result shows that thin fluid with viscosity of 1 cp to 2 cp increases SRV but it decrease PSRV because proppants are not distributed further inside of network with thin fluid. Fracture intensity increased in a reservoir with relatively smaller horizontal differential stress and natural fracture spacing. The conductivity of propped fracture network increased when fracture intensity is low and larger proppant size is used. These results will provide a better understanding to enhance SRV, fracture intensity and fracture conductivity through proper proppant, fluid and pumping rate selection depending on the differential stress and the complexity of pre-existing natural fracture network.
With gas production from gas condensate reservoirs, the flowing bottomhole pressure of the production well decreases. When the flowing bottomhole pressure becomes less than the dew point pressure, condensate accumulates near the wellbore area and forms a condensate bank. This results in loss of productivity of both gas and condensate. This becomes more serious in intermediate permeability gas-condensate reservoirs where the condensate bank reduces both the gas permeability and the well productivity.
Several techniques have been used to mitigate this problem. These methods include: gas cycling, drilling horizontal wells, hydraulic fracturing, injection of super critical CO2, use of solvents and the use of wettability alteration chemicals. Gas cycling aims to keep the pressure of the reservoir above the dew point pressure to reduce the condensation phenomena. The limited volumes of gas that can be recycled in the reservoir can hinder the application of this method. In order for an ideal recycle, gas volume injected into the reservoir will be larger than the total gas that can be produced from such a reservoir. Other approaches are drilling horizontal wells and hydraulic fracturing where the pressure drop around the wellbore area is lowered to allow for a longer production time with only single phase gas flow to the wellbore. These approaches are costly as they require drilling rigs. Another technique is the use of solvents which shows good treatment outcomes, but the durability is a questionable issue in these treatments. Moreover, wettability alteration needs to be approached very carefully as to not cause permanent damages to the reservoir. It was reported in many studies the use of fluorinated polymers and surfactants dissolved in alcohol-based solvents for wettability alterations treatments.
Each method has its own advantages and disadvantages, and can be applied under certain conditions. The paper presents all of these methods along with their advantages and disadvantages, besides description of some of their field applications and case studies.