Liquid loading is the inability of a producing gas well to remove its coproduced liquids from the wellbore. The liquid flowing as droplets or film accumulates at the well bottom, thereby imposing backpressure at the sandface and triggering increasingly higher pressure loss in the wellbore. The problem initiated by liquid loading is manifested in terms of loss in well deliverability, causing the wellhead pressure to decline significantly, which, in turn, leads to the cessation of gas production. Accordingly, the liquid-loading issue reduces the ultimate recovery of a gas well.
Both the droplet-flow reversal and liquid-film-flow reversal have been postulated to be the underlying mechanism for liquid loading. Both mechanisms are predominantly premised on diagnosing the problem at the wellhead-flow conditions. This study explores the deliquefication issue in a gas well by fluid- and heat-flow modeling of the entire wellbore for a variety of flow situations in gas and gas/condensate reservoirs.
We observed that when a well experiences annular two-phase flow throughout the wellbore, no liquid loading occurs. The transition from annular flow to churn or slug flow initiates the liquid-film-flow or droplet-flow reversal, thereby triggering liquid loading. Most often, the flow condition at the well bottom controls the onset of liquid loading. By use of three published data sets, we show that the understanding of liquid loading improves when the entire wellbore-flow modeling is used. Forward modeling suggests that the tubing inside diameter and the well productivity index are the most important independent variables in determining the critical liquid-loading rate and the onset of liquid loading.
In typical drillstem testing (DST), transient pressures are gathered downhole while rate measurements occur at the surface. Effects of heat transfer on pressure, particularly during a buildup test in a gas well, necessitate the close proximity of pressure measurements to the point of fluid entry. While pressure measurements are reliable with sufficient resolution in most settings, rate measurements often lack synergy with pressure because of the sensor resolution and the frequency of monitoring. The reduced-rate sensor resolution and rate-monitoring frequency may precipitate significant uncertainty in transient-test interpretations. This paper presents a case study for a deepwater asset in Western Australia, where, in addition to the traditional downhole-pressure and surface-rate measurements, temperatures were recorded at various depth stations in four wells, each in a different reservoir, before, during, and after transient testing. These temperature data allowed estimation of gas-flow rates. The computational accuracy of flow rates increased at shallower depths because increased heat transfer, leading to larger temperature difference, enhanced the fidelity of measurements. Overall, the distributed-temperature data allowed the estimation of temperature gradients, including their nonlinear trends, for both the static geothermal and dynamic flows.
Sustained casing pressure (SCP), exhibited by many wells, is defined as any measurable casing pressure that rebuilds after being bled down, attributable to cause(s) other than artificially applied pressures or temperature fluctuations in the well. Gas leakage, leading to SCP, may occur through the poor cement bond between the casing and the formation, packer, and/or the casing itself. All safety regulators require SCP elimination. However, test-data analysis is mostly qualitative and limited to arbitrary criteria, thereby lacking consensus. This paper attempts to provide a theoretical frame and a model for quantitative analysis of SCP-test data. Specifically, we adapted a model for SCP that is rooted in the transport processes of the system. The model accounts for mud compressibility and assumes gas is leaking into the annulus and migrating up the annular liquid column. Some robust assumptions about the transport processes allow for expressing the governing equation as a first-order, linear differential equation that is solved with appropriate boundary conditions. The resulting algebraic expression for the casing-pressure rise (Annulus A) with time is easy to apply. A comparison of the performance of the model with field data suggests that gas influx causes a casing-pressure (Annulus A) increase in wells.
The production of a substantial fraction of carbon dioxide (CO2) in any hydrocarbon-gas stream poses a significant challenge in terms of separation and sequestration. Both environmental concerns and economic incentives encourage the operators to search for safe, cost-effective ways of disposing of CO2. This paper presents a case study in which a pragmatic solution of CO2 separation at surface and its disposal in a saline aquifer occur in close proximity to its source. A suite of both modern and classical analytical tools is used to understand the production behavior of individual wells. This understanding is imperative because production volume is dictated by the ability to dispose of the associated CO2 volumes to honor the fault-activation pressure limit. The analytical tool kit--transient-productivity index (PI), combined static and dynamic material-balance (MB) methods, and rate-transient analysis (RTA), among others--allowed for the rapid assessment of both the producing gas reservoir and the saline aquifer receiving the CO2 stream. The use of real-time data allowed a comprehensive assessment of in-place volumes for the source gas and the capacity of the aquifer. The injection of supercritical CO2 suggests that the terminal aquifer pressure has been reached by encountering less-than expected storage volume and by the lowering of fracture-pressure gradient. On-time learning has allowed the asset team to search for alternative CO2-disposal solutions to ensure continuous gas production from this field.
Empirical and/or semianalytical tools are frequently applied in most waterflood operations, although grid-based models are also often used. This paper examines the performance of some commonly used tools, such as the water-oil ratio (WOR), Y-function, and Arps. Besides those tools, we introduce a semianalytical approach, which is a modified version of the Y-function formulation. Two other tools that have gained significant traction in unconventional-reservoir performance forecasting, the stretched-exponential decline model (SEDM) and the capacitance-resistance model (CRM), are also used here.
Based on synthetic and field data, the results show that the Arps method is remarkably accurate in all flooding situations, regardless of the underlying physical mechanisms; other published data tend to support this notion. Similarly, both the SEDM and the proposed modified-Y-function method also yield solutions with good accuracy. The latter solutions tend to be pessimistic, however.
Diagnostic fracture injection testing (DFIT) is an invaluable tool for evaluating reservoir properties in unconventional formations. The test comprises injection of water over a very short time period, initiating a fracture at the end of a well's horizontal section, followed by a long shut-in period. Analysis of the falloff data with the G-function plot reveals the fracture closure pressure, and the fracture pseudolinear-flow period leads to the initial reservoir pressure.
In most tests, wellhead pressure (WHP) measurements are used because of cost considerations. A wellbore heat transfer model is used to allow conversion of WHP to bottomhole pressure (BHP) by accounting for changing fluid density and compressibility along the wellbore. This model, in turn, allowed us to assess the quality of solutions generated with the WHP data. For DFIT analysis, we adapted the modified-Hall plot for the injection period, whereas both the pressure-derivative and G-function plots were used for the analysis of falloff data. The derivative signature of the modified-Hall plot allows unambiguous estimation of the fracture breakdown pressure (pfb) during the injection period. As expected, the pfb always turns out to be higher than the fracture closure pressure (pfc), estimated with the two methods during pressure falloff, thereby instilling confidence in the solutions obtained.
A statistical design of experiments with coupled geomechanical/fluid-flow simulation capabilities showed that the formation permeability is by far the most important variable controlling the fracture closure time. Mechanical rock properties, such as Young's modulus of elasticity and the Poisson's ratio, play minor roles. In microdarcy formations, a longitudinal fracture takes much longer to close than its transverse counterpart.
Estimating in-place volume associated with each well, leading to estimation of total reservoir in-place volume, is the cornerstone to any reservoir-management practice. Yet, conventional methods do not always lend themselves to routine applications, particularly when used in singular fashion. However, combining these methods on the same plot has considerable merit in that they converge to the same solution when material-balance (MB) -derived average-reservoir pressure is used in a volumetric system.
This study presents a systematic procedure for estimating the gas-initially-in-place (GIIP) volume when real-time surveillance data of pressure, rate, and temperature are available at the wellhead. Specifically, we show that log-log diagnosis, followed by combined static- and dynamic-MB analysis and transient-productivity-index (PI) analysis, leads to consistent solutions. Thermodynamic behavior of fluids is also explored to ensure that converted pressures at the bottomhole and measured rates have consistency and accuracy for reservoir-engineering calculations.
Layered systems were selected for this study because they represent most situations. Two synthetic cases probed issues pertaining to average-reservoir-pressure computation with the pseudosteady-state (PSS) approach, and two field examples validated the approach presented here.
Permeability is the cornerstone of any reservoir-flow modeling that leads to field development and production management. Typical sources of permeability include cores, logs, wireline formation tests [or minidrillstem tests (mini-DSTs)], and conventional DSTs. However, integrating various sources of permeability at different scales is problematic. Anchored in mini-DST-derived permeability, this study endeavors to integrate various sources of permeability, leading to reservoir description in a turbidite sandstone reservoir in the Sabah basin, Malaysia.
Pressure-transient-test data recorded during a mini-DST operation differed significantly from data gathered during a conventional DST. Even though test quality was excellent, interpretation challenges were numerous in this well. Consequently, multidisciplinary information was brought to bear for integration of data derived from mini-DSTs. Other sources of information included sidewall cores, spot pressure measurements, nuclear magnetic resonance (NMR), and microelectrical imaging logs. This case study demonstrates that, in this particular setting, the use of mini-DSTs was cost-effective and yielded the subsurface information required to plan field-development options.
Shayegi, Sara (Shell) | Kabir, C. Shah (Hess Corporation) | If, Flemming (Hess Corporation) | Christensen, Soren (Hess Corporation) | Ken, Kosco (Hess Corporation) | Casasus-Bribian, Jaime (Hess Corporation) | Hasan, ABM K. (Hess Corporation) | Moos, Daniel (Dong E&P)
Underbalanced drilling (UBD) offers a unique opportunity to estimate undamaged, in-situ formation properties upon first contact with the formation while drilling. This paper compares well-testing techniques developed for UBD with conventional methods. The reservoir flow rates in combination with flowing bottomhole pressures (BHPs) acquired while drilling can be used to identify productive intervals and estimate dynamic reservoir properties.
Unlike typical UBD projects where reservoir benefits are the primary focus, the driver for this mature field was overcoming the drilling problems associated with the wide reservoir-pressure variability caused by nearby producers and injectors. UBD was piloted as a means to achieving the requisite lateral lengths for reserves capture and meeting production targets. Minimizing formation damage and characterizing the reservoir while drilling were added benefits.
Several reservoir-characterization methods based on rate-transient analysis (RTA) were used to perform well testing while drilling. Rate-integral-productivity-index (RIPI) analysis uses the rate and pressure data acquired during drilling to determine whether additional holes drilled contribute and to ascertain the relative quality of this rock. In the increasing-boundary method, real-time rate and pressure data during drilling, circulating, and tripping allowed assessment of formation properties through history matching. Pressure-buildup data were also available during trips because the concentric annuli allowed the pressure to be monitored below the downhole isolation valve. These data enabled the estimation of reservoir pressure and productivity index (PI) with a proxy vertical-well model for each productive interval drilled. These interpretation methods show close agreement in results and lend credence to the UBD-derived parameters.
Production of substantial fraction of CO2 in any hydrocarbon-gas stream poses a significant challenge in terms of separation and sequestration. Both environmental concerns and economic incentives provide the operators to search for safe, cost-effective ways of disposing CO2.
This paper presents a case study where a pragmatic solution of CO2 separation at surface and its disposal in a saline aquifer occurs in close proximity to its source. A suite of both modern and classical analytical tools are used to understand production behavior of individual wells. This understanding is imperative because production volume is dictated by the ability to dispose of the associated CO2 volumes to honor the fault-activation pressure limit. The analytical tool kit comprising transient-PI, combined static and dynamic material-balance methods, rate-transient analysis, among others, paved the way for rapid assessment of both the producing gas reservoir and the saline aquifer receiving the CO2 stream.
The use of real-time data allowed a comprehensive assessment of in-place volumes for the source gas and the capacity of the aquifer. Injection of supercritical CO2 suggests that the terminal aquifer pressure has been reached by encountering less-than-expected storage volume and owing to lowering of fracture-pressure gradient. On-time learning has allowed the asset team to search for alternative CO2 disposal solutions to ensure continuous gas production from this field.