Gas transient flow in a gas pipeline and gas tank is critical in flow assurance. Not only does leak detection require a delicate model to simulate the complicated yet dramatically changed phenomena, but gas pipeline and gas tank design in metering, gathering, and transportation systems demands an accurate analysis of gas-transient flow, through which efficient, cost-effective operation can be achieved.
Traditionally, there are two types of approaches used to investigate gas-transient flow: one involves treating gas as ideal gas so that the ideal gas law can be applied and the other considers gas as real gas, allowing the gas compressibility factor to come into play. Needless to say, the former method can result in an analytical solution to gas transient flow with a deviation from the real-gas performance, which is very crucial in daily operation. The latter approach requires a numerical method to solve the governing equation, leading to instability issues with a more-accurate result. Our literature review indicated that no study considering the effect of changing gas viscosity on the transient flow was available; therefore, this effect was included in our study.
Our investigation showed that viscosity does have a significant influence on gas-transient flow in pipe- and tank-leakage evaluation. In this study, a comprehensive evaluation of all variables was performed to determine the most-important factors in the gas-transient flow. Several case studies were used to illustrate the significance of this study. Engineers can perform a more-reliable evaluation of gas transient flow by following the method we used in our study.
For robust field development and reservoir management, it is essential to properly identify reservoir uncertainties. In this paper, we present case studies on the analysis of pressure transient data acquired in one of the offshore Abu Dhabi carbonate reservoirs. The complexity of the reservoir creates a number of uncertainties in the pressure transient behavior, making application of conventional analytical solutions insufficient to fully understand the characteristic of the reservoir fluid flow behavior.
The field was first developed by drilling vertical/ deviated wells in 1980's and then horizontal sidetrack was conducted to enhance the well productivity and improve sweep efficiency since early 1990's. We reviewed the pressure transient test data throughout the field history including past surveys for original deviated holes. It was found that most tests in original vertical/ deviated holes were conducted under the oil-water two-phase flow due to the early water encroachment from the underlying thick aquifer. A close examination of these tests showed that wellbore effects associated with the oil-water two-phase flow significantly influenced the acquired pressure data masking reservoir responses. We also identified major static and dynamic uncertainties complicating the pressure transient analysis in this field. The major feature of the pressure transient behavior is a decreasing trend of the pressure derivative. Due to a number of uncertainties existing in this field, this behavior can imply more than one geological setting: thick active aquifer, faults, and vertical transmissibility reduction.
In each pressure transient analysis, we consequently examined all the identified possible mechanisms adopting different fit-for-purpose analytical and numerical models. The fit-for-purpose modeling was found efficient to evaluate many uncertain factors including geological heterogeneities, multi-phase flow effects, and even the pressure interference from neighboring wells. This approach considering all the possible mechanisms enabled us to understand remaining reservoir uncertainties to be further investigated. In other words, this study is useful to identify major reservoir uncertainties and consider further reservoir surveillance to reduce such remaining uncertainties.
This paper demonstrates the value of collecting and interpreting real-time data for reservoir surveillance. We present three examples of real-time data acquisition and interpretation. The first example shows how formation pressure while drilling (FPWD) data provides permeability quantification for placement of a horizontal lateral. Initial performance of the pilot injector confirmed optimum placement of the well demonstrating value of information (VOI) from real-time data acquisition. In addition, pressure data helped in understanding the pressure distribution along the lateral due to support from a nearby gas injector and also in adjustment of mud parameters for drilling.
The second example highlights the use of downhole fluid analysis (DFA) to confirm gas breakthrough detected earlier by open hole logs, to estimate gas oil ratio of the producer and help selection of fluid sampling point. Integrated analysis of logs, modular formation-dynamics tester (MDT) pressures, DFA results, flow test data and subsequent PVT analysis of oil provided indication of complex gas movement from injector to producer and provided insight on vertical sweep of gas.
The third example demonstrates the use of permanent downhole gauges (PDHG) data for real-time performance monitoring of a maximum reservoir contact (MRC) well. Results of the analysis show clear evidence of voidage balance from nearby MRC injector and underscore the feasibility of field development with water injection in a lower permeability area. Combining the effective well length derived from production logging tool (PLT) data, the example also illustrates pressure /rate deconvolution analysis to determine permeability and skin. Additionally, rate-transient analysis (RTA) is done using rate and high-frequency long-term pressure data to compute permeability, skin and drainage area of the well.
Al-shuaili, Khalfan H. (Petroleum Development Oman) | Cherukupalli, Pradeep Kumar (Petroleum Development Oman) | Saadi, Faisal (PDO) | Al-hashmi, Khalid Hamad (Petroleum Development Oman) | Jaspers, Henri F. (Petroleum Development Oman) | Sen, Subrata (Shell India Markets Private Ltd)
The objective of injecting polymer in brown fields is to increase recovery beyond primary and secondary recovery mechanisms. However, generally it is difficult to achieve adequate (viscous) polymer injectivity in depleted sandstone reservoirs without fracturing. Therefore, monitoring fracture propagation is required in order to control vertical conformance and areal sweep and avoid early polymer breakthrough.
Different surveillance methods are used to identify the existence and properties of fractures in polymer injectors. Pressure Fall off (PFO) survey data in conjunction with time-lapse temperature surveys are extensively used to determine the fracture dimensions. PFO tests in Polymer injectors have particular characteristics since they are influenced by shear-dependent viscosity seen in non-Newtonian fluids. A specially developed Injection Fall-off (IFO) model was used to determine fracture dimensions which is based on exact semi-analytical solution to the fully transient elliptical fluid flow equation around a closing dynamic fracture developed by Shell, (Van den Hoek 2005), as static fracture models are inadequate.
This paper presents different phenomena in polymer injection seen in PFO tests such as fracture closure, the effect in-situ polymer rheology and the detection of the polymer front. The paper demonstrates the effect of liquid-level drop observed in PFO survey in under-pressured reservoirs and its impact on determining fracture and some other reservoir properties. It also shows how plot-overlays of time lapse PFO's for a particular well can be used to track changes in fracture dimensions. All of these are illustrated by a number of field examples of polymer PFO which also demonstrate the calculated fracture dimensions from the data. Finally, some recommended best practices are suggested for fracture monitoring.
Horizontal wells are used in unconventional oil and gas reservoirs to increase production by creating large drainage surface areas and contact volumes. Production is further improved by applying hydraulic fracture stimulation in horizontal wells.
Hydraulic fracturing increases well productivity via the large drainage surface of the fracture and by rejuvenating existing natural fractures as well as creating new fractures in the vicinity of the wellbore. The affected reservoir volume is known as
the stimulated reservoir volume (SRV) which includes a complex flow network that creates different flow regimes.
We will present several short and long pressure transient tests conducted in vertical and horizontal wells, to determine critical formation properties of the low-permeability, dual-porosity Middle Bakken and Three Forks reservoirs. Pressure transient test data were obtained via permanent downhole pressure gauges. The bilinear and linear flow regimes of the pressure buildup tests are the focus of the analyses. For this, we have presented an analytical solution using numerical inverse Laplace
transform as well as closed-form approximate solutions.
Flow rate transient analysis of long-duration production data were also conducted to compare with the results of the pressure transient analyses. All tests indicated that the field measured permeability is several orders of magnitude greater than
permeability measured on core plugs. This indicates the presence of a network of interconnected fractures and microfractures in the stimulated near-well regions without which no significant production would result. The details of the well tests and
analyses will be presented for engineering applications.
The paradigm shift towards horizontal well drilling with multiple fracture stages to exploit unconventional plays has unsurprisingly resulted in a rapid growth of questions regarding the interpretation of the associated well performance
signatures on log-log diagnostic and specialized analysis plots. Log-log diagnostic plots perhaps best illustrate the sequence of flow-regimes which may result from this completion type. However, the long-term behavior one should expect to see on a
square-root-time plot from the sequence is seldom presented in the literature, in spite of the ubiquitous use of linear flow specialized plots for unconventional well performance analysis. This paper addresses frequently asked questions regarding
the meaning of the commonly observed negative y-intercepts on these plots. Using multi-frac horizontal well analytical models, synthetic production data sets were generated to evaluate various hydraulic-fracture geometries. The resulting data
signatures are presented on a dimensionless specialized plot to reveal the behavior of the early linear, transitional and (late) compound linear flow regimes. This study illustrates that negative intercepts are typically created from the transitional period
following the first linear flow and quantifies both the magnitude and sign of the resulting intercept produced from compound linear flow based on various hydraulic fracture length and spacing combinations. Using a field example, this work also
demonstrates that false interpretations of compound linear flow may arise due to the misinterpretation of the prolonged transitional flow period between the first and second linear flow regimes.
Hadibeik, Hamid (University of Texas at Austin) | Chen, Dingding (Halliburton Energy Services Group) | Proett, Mark A. (Halliburton Energy Services Group) | Eyuboglu, Abbas Sami Sami (Halliburton) | Torres-Verdin, Carlos
Pressure testing in very low-mobility reservoirs is challenging with conventional formation-testing methods. The primary difficulty is the over-extended build-up times required to overcome wellbore and formation storage effects. Possible wellbore overbalance or supercharge are additional complicating factors in determining reservoir pressure. This paper addresses the above technical complications and estimates petrophysical properties of low-mobility formations using a newly developed adaptive-testing approach.
The adaptive-testing approach employs an automated pulse-testing method for very low-mobility reservoirs and uses short drawdowns and injections followed by short pressure stabilization periods. Measured pressure transients are used in an optimized feedback loop to automatically adjust subsequent drawdown and injection pulses to reach a stabilized pressure as quickly as possible.
The automated pulse data is used to determine supercharge effects, formation pressure, and mobility via analytical models by analyzing the entire pressure sequence. A genetic algorithm estimates additional reservoir parameters, such as porosity and viscosity, and confirms results obtained with analytical models (reservoir pressure and permeability). The modeled formation pressure exhibits less than 1% difference with respect to true formation pressure, while the accuracy of other parameters depends on the number of unknown properties. As a quicker method to estimate reservoir properties, a direct neural-network regression of pulse-testing data was also investigated.
Synthetic reservoir models for low-mobility formations (M < 1 mD/cp), which included the dynamics of water- and oil-based mud-filtrate invasion that produce wellbore supercharging were developed. These reservoir models simulated the pulse-testing methods, including an automated feedback-optimization algorithm that reduces the testing times in a wide range of downhole conditions. The reservoir models included both simulations of underbalanced and overbalanced drilling conditions and enabled the development of new field-testing strategies based on a priori reservoir knowledge. The synthetic modeling demonstrates the viability of the new pulse-testing method and confirms that difficult properties, such as supercharging, can be estimated more accurately when coupled with the new inversion techniques.
Carbonate formations are highly heterogeneous with variations from grainstones to mudstones. Digenesis leads to changes of the rock's original nature, like dolomitization, vugs, layering and fracturing. These variations have effects on rock quality in terms of porosity and permeability. Similarly, clastics, including shaly sands, can be quite challenging in terms of accurate formation evaluation.
Although extensive logs are run for the petrophysical evaluations in these formations, the use of advanced wireline formation testers (WFTs) greatly aids reservoir description. Standard formation evaluation tools and techniques sometimes result in low level of confidence in identifying and quantifying the presence of hydrocarbon in certain reservoirs. The application of modern wireline formation testers has become a useful tool in minimizing uncertainties in situations where we have low confidence in log evaluation. Some borehole conditions and reservoir architectures, like fractures, vugs, and low mobility and mud losses could also pose some challenges while performing formation testing.
In this paper, several examples and case histories of the application of advanced wireline formation testers across varieties of rocks with fractures, vugs and different borehole conditions are presented. Results indicate that reservoir heterogeneities can be described and quantified more accurately with the integration of dynamic data to aid reservoir characterization. This paper also demonstrates how to handle the challenges of detecting the early traces of hydrocarbon arrival for real time decisions during pressure testing and sampling.
The exploitation of unconventional reservoirs goes hand in hand with the practice of hydraulic fracturing and, with an ever increasing demand in energy, this practice is set to experience significant growth in the coming years. Sophisticated analytic models are needed to accurately describe fluid flow in a hydraulic fracture and the problem has been approached from different directions in the past 3 decades, starting with the work of Gringarten et al. (1974) for an infinite conductivity case, followed by contributions from Cinco et al. (1978), Lee and Brockenbrough (1986), Ozkan and Raghavan (1991) and Blasingame and Poe (1993) for a finite-conductivity case. This topic is still an active area of research and, for the more complicated physical scenarios such as multiple transverse fractures in ultra-tight reservoirs, answers are presently being sought.
Starting with the seminal work of Chang and Yortsos (1990), fractal theory has been successfully applied to pressure transient testing, albeit with an emphasis on the effects of natural fractures in pressure-rate behavior. In this paper, we begin by performing a rigorous analytical and numerical study of the Fractal Diffusivity Equation and show that it is more fundamental than the classic linear and radial diffusivity equations. Subsequently, we combine the Fractal Diffusivity Equation with the trilinear flow model (Lee and Brockenbrough 1986), culminating in a new semi-analytic solution for flow in a finite-conductivity vertical fracture which we name the "Fractal Fracture Solution??. This new solution is very fast and its accuracy is comparable to that of the Blasingame and Poe solution (1993). In its final, closed form, it is valid for a dimensionless fracture conductivity FcD = 3. Ultimately, this project is a demonstration of the untapped potential of fractal theory; our approach is very flexible and we are optimistic about extending the same methodology to develop new solutions for pressing problems that the industry currently faces, the only caveat being that it must calibrated to a known solution or production history.
Despite unequivocal advantages of using sampled well-performance data in the Laplace transform domain, time-domain analysis of pressure and production data have been more popular lately. This is because of the unresolved problems in the transformation of sampled data to Laplace domain as opposed to the demonstrated success of the recent real-time deconvolution algorithms. However, the transformation of sampled data to Laplace domain has a broader range of applications than deconvolution and the limited success of the past approaches to transform tabulated data to Laplace domain, such as piece-wise linear approximations, is an algorithmic issue; not a fundamental defect. Specifically, an adequate algorithm to transform the piecewise-continuous sampled data into the Laplace space and an appropriate numerical Laplace inversion algorithm capable of processing the exponential contributions caused by the tabulated data are essential to exploit the potential of Laplace domain operations.
In this paper, we introduce a new algorithm which uses inverse mirroring at the points of discontinuity and adaptive cubic splines to approximate rate or pressure versus time data. This algorithm accurately transforms sampled data into Laplace space and eliminates the Numerical inversion instabilities at discontinuities or boundary points commonly encountered with the piece-wise linear approximations of the data. The approach does not require modifications of scattered and noisy data or extrapolations of the tabulated data beyond the end values.
Practical use of the algorithm presented in this paper has applications in a variety of Pressure Transient Analysis (PTA) and Rate Transient Analysis (RTA) problems. Our renewed interest in this procedure has arisen from the need to evaluate production performances of wells in unconventional reservoirs. With this approach, we could significantly reduce the complicating effects of rate variations or shut-ins encountered in well-performance data. Moreover, the approach has proven to be successful in dealing with the deconvolution of highly scattered and noisy data. To illustrate the applications, typical field examples, including shale-gas wells, are presented in the paper.