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This article focuses on interpretation of well test data from wells completed in naturally fractured reservoirs. Because of the presence of two distinct types of porous media, the assumption of homogeneous behavior is no longer valid in naturally fractured reservoirs. This article discusses two naturally fractured reservoir models, the physics governing fluid flow in these reservoirs and semilog and type curve analysis techniques for well tests in these reservoirs. Naturally fractured reservoirs are characterized by the presence of two distinct types of porous media: matrix and fracture. Because of the different fluid storage and conductivity characteristics of the matrix and fractures, these reservoirs often are called dual-porosity reservoirs.
This section focuses on handling uncertainity and lack of data in geomechanical design. If few, or no, wells have been drilled in an area, or few measurements exist from earlier wells, developing a reliable geomechanical model will be more challenging. It is not necessary to have a well-constrained stress state to utilize geomechanical design principals. Sometimes, knowing just the stress regime (normal, strike-slip, or reverse), it is possible to estimate relative risk as a function of wellbore deviation and determine the importance of knowing the stress orientation. If geological analysis provides information about stress orientation as well, it is also possible to determine the relative risk as a function of wellbore azimuth. Figure 1 shows relative wellbore stability as a function of wellbore orientation at 5,000 ft in normal, strike-slip, and reverse-faulting regimes.
Produced-water reinjection (PWRI) is an important strategy for deriving value from waste water, but its implementation can face challenges related to injectivity and safety issues. The first objective of a PWRI-design study is to supply water-quality specifications, and the second is to supply injection-pressure specifications. The objective of this paper is to detail how water quality and injection pressure are deduced when uncertainties of input data are considered. Before any PWRI design commences, a feasibility study is performed to assess any compatibility issues and evaluate the risk of scaling and souring and the viability of the project. Bacteria growth and corrosion of the installations have to be tackled and mitigated upstream in the early phase of the project.
Summary For an empty fracture, the fracture permeability (kf) is mainly influenced by the effect of viscous shear from fracture walls and can be analytically estimated if the fracture width (wf) is known a priori (i.e., , where β2 is the unit‐conversion factor). For an adequately propped fracture, the fracture permeability is mainly influenced by the proppant‐pack properties and can be approximated with the proppant‐pack permeability (, where kp is proppant‐pack permeability). It can be readily inferred that as the effect of viscous shear fades (or the proppant‐pack effect becomes pronounced), there should be a regime within which both the viscous shear and the proppant‐pack properties exert significant influences on the fracture permeability. However, the functional relationship between fracture permeability, viscous shear (or fracture width), and proppant‐pack properties is still elusive. In this work, we propose a new fracture‐permeability model to account for the influences of the proppant‐pack permeability, proppant‐pack porosity (ϕp), and fracture width on the fracture permeability. This new fracture‐permeability model is derived from a modified Brinkman equation. The results calculated with the fracture‐permeability model show that with different values of the Darcy parameter, the fluid flow can be divided into viscous‐shear‐dominated (VSD) regime, transition regime, and Darcy‐flow‐dominated (DFD) regime. If the Darcy parameter is sufficiently large, the effect of proppant‐pack permeability on fracture permeability can be neglected and the fracture permeability can be calculated with the VSD fracture‐permeability (FP) (VSD‐FP) equation (i.e., ). If the Darcy parameter is sufficiently small, the effect of viscous shear on fracture permeability can be neglected and the fracture permeability can be calculated with the DFD‐FP equation (i.e., ). Both the VSD‐FP and DFD‐FP equations are special forms of the proposed fracture‐permeability model. For the existing empirical/analytical fracture‐conductivity models that neglect the effect of viscous shear, one can multiply these models by the coefficient of viscous shear to make these models capable of estimating the fracture conductivity with large values of Darcy parameter.
Iftikhar Choudhry, Bilal (ADNOC Offshore) | Khaled Abdelkarim, Islam (ADNOC Offshore) | Cantarelli, Elena (Schlumberger) | Johannes Ness, Knut (ADNOC Offshore) | Esposito Gonzalez, Juan (ADNOC Offshore) | Landaeta Rivas, Fernando Jose (ADNOC Offshore) | Torres Premoli, Javier (ADNOC Offshore)
On several occasions during drilling, the drill string or in cases of liner job the liner string comes across an overall regressive environment. By regressive environments, the condition of the well bore returning to its unconditioned and in some cases unstable phase, is implied. The objective of this paper is to see how the regression impacts the circulating pressures in particular and how best to anticipate such conditions to optimize/modify the practices. The circulating pressures in deteriorated/reverted cases start showing spikes in the actual values well beyond the predicted models subsequent to same flow rates at the same depths. Such deviations in the actual vs theoretical values can pose severe complications for the drilling and liner jobs. These resultant complications however can be countered with the help of hydraulic mapping and gel envelope estimation in conjunction with optimized tripping and circulation practices for the respective operations to ameliorate the conditions.
This paper explores the impact of regressive hole conditions ranging from constraints, operability, mechanical loads and fluid regimes. It builds upon that impact and delves into how best to utilize the tool of hydraulic mapping for smooth tripping and drilling operations in conjunction with the real time monitoring to define the operational envelopes. Delving into the dynamics of the hole conditions in regards to tripping and drilling operations across open hole, the paper seeks to build upon experience and reach an optimized mantle for tripping, drilling, circulation and conditioning operations in compromised hole conditions without any time delay or complication.
During the life span of the well operations, the open hole well bore conditions of the wells become adverse to continuing onwards with the operations without at first conditioning or changing the downhole states altogether. This is the modus operandi for the majority of operations but in instances where the ambient impact is time sensitive or where the operations altogether are too complex and constrained for that to be done, the well conditions worsen, and the complications related to the ongoing operations increase manifold, rendering the operation in extreme cases unfeasible altogether. This likelihood can however be circumvented with the help of preventive intervention tools such as hydraulic mapping.
There is no broad stroke solution to operational complications though, techniques and tools vary with each instance and are very case specific in both spectrum of definition and application. The most significant take away though, is how the incorporation of hydraulic mapping ensures the impending operational problems and complications are efficiently and specifically managed without any downtime or operational delay, on the fly. There are cases when the hydraulic and dynamic parameters have been mapped with upper limits built within the model yielding successful execution of operations against odds. In presence of rapid gelation or excessive gel breaking pressures against high differential formations, the practice of rotating prior to circulation or reciprocation prior to circulation are also determined with this tool.
Real time operations monitoring also play a pivotal role in benchmarking and tracking the operational parameters of interest that are critical for operations. In order to achieve that however, there needs to be a composite model for the real time broomstick to be in place that reflects the overall picture of the open hole well bore. The hydraulic mapping technique requires minor inputs from the routine operational practices but forms an integral tool that can help execute operations effectively in jeopardized environments, against staggering odds without forfeiting any of the operational parameters or objectives.
When drilling challenging formations such as very thick highly fractured sour reservoirs or carbonate/karst formations, a lost-circulation zone can be encountered. This causes mud to be lost and gas kick to take place, making the drilling process uncontrollable. Blocking or plugging wide fractures is impossible in many cases, which results in severe safety issues associated with toxic gases.
This study investigates an application of mud cap drilling by injecting foam mixture into the annulus for well control in such harsh conditions. An annular fluid column with foam mixture can be used to prevent kicks and push the toxic gas back into the formation down along the annulus. This foam-assisted mud cap drilling process has been proved to reduce non-productive time and fluid expenses.
This study presents how to model and simulate the process with accurate foam characteristics when foams are used to suppress gas kicks under certain well and fluid conditions. More specifically, this study deals with three scenarios: Base Scenario with a relatively short response time such that the injected foams do not contact the formation gas, and Scenario 1 and 2 with a relatively long response time such that the injected foams interact with the gas, with and without foam coalescence respectively, at the foam/gas interface. The results show how mud-cap drilling parameters (such as pressure, foam density (or, equivalent mud weight), foam velocity, and foam quality) change at different operating conditions and scenarios. Non-Newtonian foam rheology, depending on bubble size and bubble size distribution as modeled by
Solovyev, Timur (SevKomNeftegaz) | Ivanov, Alexander (SevKomNeftegaz) | Soltanov, Dzheykhun (SevKomNeftegaz) | Meshkov, Victor (RN-Purneftegaz) | Kamalov, Artur (RN-Purneftegaz) | Nagimov, Vener (TGT Oilfield Services) | Trusov, Alexander (TGT Oilfield Services) | Aslanyan, Irina (TGT Oilfield Services) | Makarov, Dmitry (TGT Oilfield Services)
Abstract The complex interbedded heterogeneous reservoirs of the Severo-Komsomolskoye field are developed by horizontal wells in which, as part of the pilot project's scope, autonomous inflow control devices (AICD) are installed to prevent early coning and gas breakthroughs in long horizontal sections and reduce sand production, which is a problem aggravated by an extremely low mechanical strength of the terrigenous deposits occurring in the Pokur formation of the Cenomanian stage in this area. The zones produced through AICDs are separated by swell packers. The issue of AICD effectiveness is discussed in the publications by Solovyev (2019), Shestov (2015), Byakov (2019) and some others. One of the methods used for monitoring horizontal sections with AICDs is production logging (PLT). However, due to the complexity of logging objectives, the use of conventional logging techniques makes the PLT unfeasible, considering the costs of preparing and carrying out the downhole operations. This paper provides some case studies of the Through-Barrier Diagnostics application, including passive spectral acoustics (spectral acoustic logging) and thermohydrodynamic modelling for the purpose of effective estimation of reservoir flows behind the liner with AICDs installed and well integrity diagnostics. As a result of the performed diagnostics, the well completion strategy was updated and optimised according to the log interpretation results, and one well intervention involving a cement squeeze with a straddle-packer assembly was carried out.
This paper proposes the difference-value plotting function (DVPF) for the diagnostic analysis and interpretation of pressure transient test data in low-permeability reservoirs. Specifically, this work uses the approximation of the analytical solution for the performance of a vertical well with a single finite conductivity vertical fracture, where a Taylor Series expansion is used to obtain an asymptotic solution for early-time flow, which includes terms for wellbore storage and fracture conductivity. The well-testing derivative of this result is then obtained and is of a similar form.
By subtracting the derivative form from the pressure form, we remove the "dominant" wellbore storage term from the asymptotic solution. We then need to normalize that difference by the square root of time (or dimensionless time) to obtain the final formulation of the DVPF which leaves a single constant parameter multiplied by time on the right-hand-side. Our contention is that this formulation leaves us with a diagnostic plotting function which provides a unique and contrasting behavior compared to using the pressure drop and/or pressure drop derivative functions alone for diagnostics and interpretations.
As is typical of pressure transient or well testing data at early times, the observed pressures often exhibit random data noise. As such, we have adapted a noise reduction algorithm that was originally used for signal processing to smooth both the pressure and derivative functions.
Lastly, we demonstrate the difference-value plotting function (DVPF) on several cases of synthetic and field-derived data to illustrate the utility of this methodology. Specifically, we have applied this method to cases in which it is difficult to determine unique interpretations using traditional methods (e.g., insufficient duration tests, lengthy WBS distortion, and effects of ultra-low permeability). The proposed DVPF allows us to observe underlying characteristics that are obscured at early times in traditional pressure and derivative analysis, and for the demonstration examples provided in this work, the DVPF does provide a strong auxiliary means of interpretation.
Summary To minimize fluid loss and the associated formation damage, foam is a preferred fluid to perform cleanout operations and reestablish communication with an open completion interval. Because of their high viscosity and structure, foams are suitable cleanout fluids when underbalanced well-cleanout operations are applied. Although several studies have been conducted to better understand foam-flow behavior and hydraulics, investigations performed on foam stability are very limited. Specifically, very little is known regarding the impact of wellbore inclination on the stability of foams. Unstable foams do not possess high viscosity, and as a result, they are not effective in cleanout operations, especially in inclined wellbores. Predicting the downhole instability of foam could reduce the number of drilling problems associated with excessive liquid drainage, such as temporary overbalance, formation damage, and wellbore instability. The objectives of this study are to investigate the effects of wellbore inclination on the stability of various types of foams and develop a method to account for the effect of inclination on foam stability in inclined wells. In this study, foam-drainage experiments were performed using a flow loop that consists of a foam-drainage-measurement section and pipe viscometers. To verify proper foam generation, foam viscosity was measured using pipe viscometers and compared with previous measurements. Drainage experiments were performed with aqueous, polymer-based, and oil-based foams in concentric annulus and pipe under pressurized conditions. Tests were also conducted in vertical and inclined orientations to examine the effect of wellbore inclination on the stability of foams. The foam-bubble structure was examined and monitored in real time using a microscopic camera to study bubble coarsening. The foam quality (i.e., gas volume fraction) was varied from 40 to 80%. Results show that the drainage rates in the pipe and annular section were approximately the same, indicating a minor effect of column geometry. More importantly, the drainage rate of foam in an inclined configuration was significantly higher than that observed in a vertical orientation. The inclination exacerbated foam drainage and instability substantially. The mechanisms of foam drainage are different in an inclined configuration. In inclined wellbores, drainage occurs not only axially but also laterally. As a result, the drained liquid quickly reaches a wellbore wall before reaching the bottom of foam column. Then, a layer of liquid forms on the low side of the wellbore. The liquid layer flows downward because of gravity and reaches the bottom of the test section without facing the major hydraulic resistance of the foam network. This phenomenon aggravates the drainage process considerably. Although foam-drainage experiments have been reported in the literature, there exists only limited information on the effects of geometry and inclination on foam drainage and stability. The information provided in this paper will help to account for the effect of inclination on foam stability and subsequently improve the performance of oilfield operations involving foam as the working fluid.
The paper considers the problem of isothermal filtration of a binary hydrocarbon mixture in a porous medium, taking into account capillary pressure and the presence of retrograde regions of the phase diagram. The thermodynamic properties of the model mixture were calculated using the Peng - Robinson equations of state. The Lorentz - Bray - Clark relations were used to determine the viscosity of the phases, and the Gillespie - Lerberg equation was used to determine the chemical potentials. The functions of the relative phase permeability were specified in the form of empirical formulas of Chen Chzhun Xiang. The system of differential equations describing the modeled process was solved by the finite element method in the FlexPDE environment. It is shown that for given thermobaric conditions for filtering a binary mixture through a porous medium, time-varying changes in saturation, mixture composition, and mass flow rate of the liquid and vapor phases at the exit of the experimental model are possible. For the case of filtration of a model gas-condensate mixture of methane - butane, the problem was solved in an equilibrium and non-equilibrium formulation, and in both cases, the calculation results confirm the assumption about the cyclic formation of a liquid plug and its movement inside the simulated section. It is shown that taking into account nonequilibrium leads to a change in the pressure field along the filtration path, the amplitude and shape of the resulting self-oscillations in the flow rate of the vapor and liquid phases. These features must be taken into account when interpreting unsteady regimes of real (nonequilibrium) flows of reservoir fluids in the bottomhole formation zone. The proposed model can be used to assess the effectiveness of technologies for increasing the flow rate of gas condensate wells by affecting the bottomhole formation zone, as well as when calculating the flow rate of a well, taking into account the possibility of unsteady filtration modes.