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.
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.
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.
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.
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.
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.
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 Martin Linge field was discovered in the 1970's but never developed due to a number of uncertainties. The complex structural settings of the Brent reservoirs was the main issue: transmissibility through the numerous faults has a direct impact on the number and type of development wells required for an appropriate drainage of the field, hence on the economy of the project
In 2009/2010 Total drilled an innovative appraisal well to de-risk this challenging development. The primary objective was to evaluate the dynamic connectivity through faults on the Upper Brent level of Martin Linge East with an Extended Well Test (EWT)
A program for the EWT (6 months duration), was defined and implemented in order to ensure conclusive results for the development strategy.
The well design included an innovative completion system with acoustic wireless down-hole gauges and a communication system to transfer the pressure data up to sub-sea well-head and then to shore via a communication link. This made it possible to obtain extended pressure build-up data after the rig had left. The test targeted the uppermost Brent reservoir of Balta only.
Analytical models were used to evaluate the investigated volume. This volume turned out to be significantly greater than the Balta reservoir accumulation, proving that the faults allow communication not only laterally but also vertically with the underlying Upper Brent Tarbert reservoir.
Due to the structural complexity of the field and the large investigation, the Eclipse reservoir model was also used to match the EWT data with the earth model. The EWT simulations in this model highlight the high lateral and vertical connectivity through major faults.
Steam assisted gravity drainage (SAGD) is the most promising technique in heavy oil recovery. Determination of the steam chamber volume is very important for monitoring the progress of this process. Thermal well testing offers an early method to estimate the steam chamber mobility and volume using pressure falloff tests. However, well test analysis of horizontal wells is more complex than that of vertical wells.
Pseudo steady state method is used to estimate the chamber volume from falloff testing assuming a composite reservoir. Due to the large contrast in the fluid mobility of the swept and un-swept zone, the flood front behaves as an impermeable boundary. Therefore, the steam chamber acts as a closed reservoir and the pressure response is characterized by pseudo steady state behavior.
The purpose of this work is to evaluate the feasibility and accuracy of thermal well test analysis for horizontal wells in SAGD process. Pressure falloff test is simulated using a numerical thermal simulator. The generated pressure falloff data are then analyzed to calculate swept volume and reservoir parameters. Effects of several parameters like permeability anisotropy, steam quality, injection rate and time on well test results are also studied.
Results of this study show that steam chamber volume and mobility and skin factor can be reasonably estimated from pressure falloff tests, and are in good agreement with simulated results. Longer injection times prior to shut-in, prove to have an adverse effect on the estimated swept volume because of a more irregular shape of swept region and the possibility of early breakthrough. Irregular swept region shape, however, does not significantly affect the early time well test data. Calculated swept volume is highly sensitive to the ratio of vertical to horizontal reservoir permeability. Finally, higher steam quality results in more accurate estimations.