Summary The accomplishment of matrix stimulation in highly contrasted permeability reservoirs is critically dependent on diversion. Consequently, assessment of the diversion performance is a key to determine the success of stimulation. However, there are still doubts on the evaluation of diversion effectiveness, especially in long‐interval heterogeneous reservoirs. When a diverter enters the formation, a hump in the surface pressure curve is usually expected. Then, it can be interpreted as supporting evidence for diversion. However, this is a simplification of the fluid‐diversion process. It could be possible that a hump is not observed during a diversion stage, although it is effective. Therefore, what should be done? To overcome this challenge, we propose a more‐accurate diversion‐evaluation method and validate it with available matrix‐stimulation data. Three methods were introduced in the literature to evaluate matrix‐stimulation performance: Paccaloni, Prouvost, and Chan [inverse injectivity (i.e., Iinv)] methods (Prouvost and Economides 1987, 1989; Paccaloni and Tambini 1993; Chan et al. 2003). The latter is easy to use and accurate, which accounts for transient flow effects. In this paper, the inverse injectivity method is modified and validated with the real data of two matrix‐acidizing operations in a gas/condensate field. The performed modifications in the evaluation process include a bottomhole‐pressure‐calculation procedure, which is validated with available drillstem‐test (DST) matrix‐stimulation data, and simultaneous utilization of Iinv and its derivative plot. Humps in the Iinv plot, which can be interpreted as diverter performance, are sometimes so small that it is difficult to distinguish the diverter effect from possible noises in the data. Here, the derivative plot of Iinv is used as a complementary tool to improve the interpretation process. Results indicate that for both wells in this study, the modified Iinv shows clear humps when diverters enter the reservoir. In addition, exactly when Iinv builds up, a sign change in the derivative plot is observed. This shows that these two parameters have a confirming behavior. Finally, pre/post‐stimulation production data were used to practically prove the calculations behind the method. Here, the target of design was to divert stimulation fluids to the low‐permeability bottom layer because it was both a high-pressure and high-hydrocarbon reserve. Per production‐logging data, the majority of production before stimulation was originated from a sublayer. In the first operation, with the rare appearance of surface pressure humps, Iinv and its derivative showed satisfactory outputs of diversion occurrence. After stimulation, production logging confirmed the diversion of flow and nearly uniform production across the targeted interval. Hence, this indicates that the modified method accurately demonstrates the performance of the diversion system in acidizing operations with long perforated intervals, even if there is a rare distinct pressure hump in the surface. Therefore, this could be adapted either for cases where there is no access to the production logging or for the cases in which the hump in surface pressure is not observed.

Apache found something positive to say about its huge gas-producing play in the Permian at a time when gas is selling at rock-bottom prices. When it shut in a 14-well pad on its Alpine High play for 60 days, gas and condensate production surged. It was a rare test of whether a production break can allow water in rock near the fracture face to soak in deeper, allowing gas and liquids to flow more freely. "The gas rate came back above the pre-soak rate and it's actually holding in pretty flat, so it shows there was some impact and the condensate rate came in higher than the pre-soak rate," said Dave Pursell, executive vice president of planning, reserves and fundamentals, during the company's third quarter earnings call. The wells were on the huge Blackfoot pad, which Apache had highlighted a year ago as a major test of the industry trend toward concentrating many wells at a single location to reduce development costs.

A common approach to forecast production from unconventional reservoirs is to extrapolate single-phase flow solutions. This approach ignores the effects of multi-phase flow, which exist once the reservoir pressure falls below the bubble/dew point. This work introduces a new two-phase (oil and gas) flow solution suitable to extrapolating oil and gas production using scaling principles. Additionally, this study compares the application of the two-phase and the single-phase solutions to estimates of production from tight oil wells in the Wolfcamp Formation of West Texas.

First, we combine the oil and the gas flow equations into a single two-phase flow equation. Second, we introduce a two-phase pseudo-pressure to help linearize the pressure diffusivity equation. Third, we cast the two-phase diffusion equation into a dimensionless form using inspectional analysis. The output of the model is a predicted dimensionless flow rate that can be easily scaled using two parameters: a hydrocarbon pore volume and a characteristic time. This study validates the solution against results of a commercial simulator. We also compare the results of both the two-phase and the single-phase solutions to forecast wells.

The results of this research are the following. First, we show that single-phase flow solutions will consistently underestimate the oil ultimate recovery factors for solution gas drives. The degree of underestimation will depend on the reservoir and flowing conditions as well as the fluid properties. Second, this work presents a sensitivity analysis of the PVT properties that shows that lighter oils (more volatile) will yield larger recovery factors for the same drawdown conditions. Third, we compare the estimated ultimate recovery (EUR) predictions for two- and single-phase solutions under boundary-influenced flow conditions. The results show that single-phase flow solutions will underestimate the ultimate cumulative oil production of wells since they do not account for liberation of dissolved gas and its subsequent expansion (pressure support) as the reservoir pressure falls below the bubble point. Finally, the application of the two-phase model provides a better fit when compared with the single-phase solution.

The present model requires very little computation time to forecast production since it only uses two fitting parameters. It provides more realistic estimates of ultimate recovery factors and EUR, when compared with single-phase flow solutions, since it considers the expansion of the oil and gas phases for saturated flow. Finally, the solution is flexible and can be applied to forecast both tight oil and gas condensate wells.

Summary

The accomplishment of matrix stimulation in highly contrasted permeability reservoirs is critically dependent on diversion. Consequently, assessment of the diversion performance is a key to determine the success of stimulation. However, there are still doubts on the evaluation of diversion effectiveness, especially in long-interval heterogeneous reservoirs. When a diverter enters the formation, a hump in the surface pressure curve is usually expected. Then, it can be interpreted as supporting evidence for diversion. However, this is a simplification of the fluid-diversion process. It could be possible that a hump is not observed during a diversion stage, although it is effective. Therefore, what should be done? To overcome this challenge, we propose a more-accurate diversion-evaluation method and validate it with available matrix-stimulation data.

Three methods were introduced in the literature to evaluate matrix-stimulation performance: Paccaloni, Prouvost, and Chan [inverse injectivity (i.e., I_inv)] methods (Prouvost and Economides 1987, 1989; Paccaloni and Tambini 1993; Chan et al. 2003). The latter is easy to use and accurate, which accounts for transient flow effects. In this paper, the inverse injectivity method is modified and validated with the real data of two matrix-acidizing operations in a gas/condensate field. The performed modifications in the evaluation process include a bottomhole-pressure-calculation procedure, which is validated with available drillstem-test (DST) matrix-stimulation data, and simultaneous utilization of I_inv and its derivative plot. Humps in the I_inv plot, which can be interpreted as diverter performance, are sometimes so small that it is difficult to distinguish the diverter effect from possible noises in the data. Here, the derivative plot of I_inv is used as a complementary tool to improve the interpretation process.

Results indicate that for both wells in this study, the modified I_inv shows clear humps when diverters enter the reservoir. In addition, exactly when I_inv builds up, a sign change in the derivative plot is observed. This shows that these two parameters have a confirming behavior. Finally, pre/post-stimulation production data were used to practically prove the calculations behind the method.

Here, the target of design was to divert stimulation fluids to the low-permeability bottom layer because it was both a high-pressure and high-hydrocarbon reserve. Per production-logging data, the majority of production before stimulation was originated from a sublayer. In the first operation, with the rare appearance of surface pressure humps, I_inv and its derivative showed satisfactory outputs of diversion occurrence. After stimulation, production logging confirmed the diversion of flow and nearly uniform production across the targeted interval.

Hence, this indicates that the modified method accurately demonstrates the performance of the diversion system in acidizing operations with long perforated intervals, even if there is a rare distinct pressure hump in the surface. Therefore, this could be adapted either for cases where there is no access to the production logging or for the cases in which the hump in surface pressure is not observed.

In this work, we assess the historical well performance for a mature gas condensate field in Oman (the field name is designated as "BHA," where "BHA" is a pseudonym). The reservoirs of the BHA field are complex and have low permeabilities which results in substantial uncertainty in reserves estimation, which in turn has resulted in regular modifications of the booked volumes. To confine these booked volumes, we employed two techniques: "time-rate" analysis (or Decline Curve Analysis (DCA)) and "time-rate-pressure" analysis (or Rate Transient Analysis (RTA)). To perform the decline curve analysis work we used Microsoft Excel to match data using both the Modified Hyperbolic (MH) and Power-Law Exponential (PLE) DCA relations. We also used the Kappa Engineering product "Topaze" to conduct the Rate Transient Analysis (or RTA) by first estimating reservoir parameters and then performing a simulation history match of both the rate and pressure data. The DCA and RTA models were both used to construct a 30-year forecast and 30-year EUR values were obtained using these forecasts. Finally, we created parametric correlations using estimated reservoir properties from RTA and the matched parameters obtained using the MH and PLE relations for DCA. The core purpose of this work was to provide assurance in the booked reserves volumes for these low permeability reservoirs and to obtain correlations of reserves and reservoir property estimates for fields like the BHA field.

Summary Significant advances have been made in the development of analytical models for performing rate-transient analysis (RTA) for single-phase oil and gas reservoirs. The primary complication associated with the adaptation of these solutions to wells exhibiting multiphase flow is the single-phase assumption in the development of the material-balance time function. Despite some efforts in modifying existing dry-gas formulations for use with gas/condensate reservoirs, that approach is not practical for analyzing multiphase flow from oil wells with multiphase-flow characteristics. In this work, we present a simple yet semianalytical model that provides a solution for analyzing production data from wells exhibiting multiphase flow during boundary-dominated flow periods. The solution is obtained by combining the material-balance equation and the productivity index (PI) for all flowing phases. Appropriately defined total pseudopressure and total pseudotime are introduced to handle the associated multiphase nonlinearities in the governing flow equations of oil, gas, and water phases simultaneously. A generalized flowing-material-balance (FMB) equation is derived from the total pseudovariables to estimate original fluid in place and drainage area (given volumetric input). The presented model provides a theoretical framework for analyzing production data considering a wide variety of reservoir-fluid systems. The new method is validated against numerical simulation, covering a wide range of fluid properties and operating conditions. In all simulated cases, the new method matches simulation input acceptably. Two field examples are also analyzed to demonstrate the practical applicability of this approach. This work serves as a practical and simple engineering tool for production-data analysis on wells exhibiting single and multiphase flow during boundary-dominated flow.

Abstract Horizontal drilling accompanied with Hydraulic fracturing makes the unconventional reservoir a viable addition to worldwide production. Hydraulic fracturing of a well is the largest cost when evaluating total well expense. Therefore, understanding the fracture performance is fundamental to the success of a shale well. The two main factors controlling a shale horizontal wells performance is completion design and reservoir quality. The completion efficiency depends on factors such as well spacing, stage spacing, cluster spacing, fluid volume, proppant type and volume, injection rate, type of fracture fluid and gas price. There are many techniques used to evaluate the hydraulic fracture performance. Some include post fracture analysis, tracer analysis, micro seismic analysis, rate transient analysis, production log analysis, fiber optics data and pressure transient analysis. This paper presents the integration of completion data, petrophysical data, fluid sample analysis, mini-frac analysis, and flowback data in matching long term buildup data. More than 6 months of data was collected for one of the unique shale gas condensate wells during the appraisal stage of an area. The analysis showed the effect of liquid drop out and phase segregation in the flow regimes. Also, this paper presents a different analytical model used to match the actual buildup data. The resulting model is used in building a reservoir model to forecast performance for the well.

Abstract In this study, we analytically cross examine the consistency among available zero-dimensional material balance equations (MBEs) for liquid-rich gas equations and derive a new simple yet rigorous MBE starting from governing equations applicable to these systems. We propose a new zero-dimensional (i.e. tank) material balance equation that is directly applicable to the analysis of liquid-rich (wet and retrograde) gas reservoirs by expression of the equations in term of an equivalent gas molar density. Following model development, proposed model predictions of gas reservoir behavior with varying condensate content (lean, intermediate and rich) are investigated and critically compared to previous zero-dimensional models. All models are employed to predict reservoir performance given reservoir original-fluids-in-place and compared against benchmark examples created by numerical simulation. Actual field examples are also analyzed using existing and proposed models to test the ability of the proposed models to provide reliable reserve estimations using straight-line methods. The proposed density-based equation is proven to be straightforward to implement since is written in terms of density. This, in turn, allows it be directly expressed as an extension of the dry gas MBE, while not requiring the implementation of two-phase Z-factors.

Abstract With the current focus on liquids-rich shale plays (LRS) in North America and the importance of gas condensate reservoirs globally, there is an increased need to develop reservoir engineering methods to analyze such reservoirs. Commercialization of LRS plays is now possible due to new technology, such as multi-fractured horizontal wells (MFHW). Efficient production from such reservoirs necessitates understanding of flow mechanisms, reservoir properties and the controlling rock and fluid parameters. Production-decline analysis is a robust technique for analysis of production data and obtaining estimates of recoverable reserves. Nevertheless, these techniques, developed for conventional reservoirs, are not appropriate for ultra-low permeability reservoirs. There are substantial differences in reservoir performance characteristics between conventional and ultra-low permeability reservoirs. LRS reservoirs produce much leaner wellstreams compared to conventional reservoirs due to very low permeabilities that result in very large drawdowns. Methods for analysis of two-phase flow in conventional reservoirs, with underlying simplifying assumptions, are no longer applicable. This paper discusses production data analysis of constant flowing bottomhole pressure (FBHP) wells producing from LRS (gas condensate) reservoirs. A theoretical basis is developed for a gas condensate reservoir during the transient linear flow (drawdown) period. The governing flow equation is linearized using appropriately defined two-phase pseudopressure and pseudotime functions so that solutions valid for liquids can be applied. The derived backward model is employed to compute the linear flow parameter, xf√k. Simulation results show that the liquid yield will be approximately constant for LRS wells during the transient linear flow, from the early days of initial testing, if flowing BHP is almost constant. An analytical formulation is used to prove this finding for 1D transient linear flow of LRS wells. The proposed production data analysis (PDA) method is illustrated using simulated production data for different fluid models and relative permeability curves. Fine-grid compositional and black oil numerical models are used to this purpose.

Abstract Development of a condensate bank in gas condensate wells producing below the dew point pressure causes productivity losses as gas mobility at the wellbore is reduced. The same is true in volatile oil wells producing below the bubble point pressure due to the existence of a gas bank. Using compositional simulation, this paper investigates the use of back-pressure plots expressed in terms of pressure, singlephase pseudo-pressure, and two-phase pseudo-pressure to describe well productivity losses below saturation pressure for gas condensate or volatile oil wells. It is shown that the theoretical stabilized back-pressure deliverability straight line at krg =krgi cannot be obtained using pressure and single-phase pseudo-pressure back-pressure plots whereas it can matched with two-phase pseudo-pressures, provided that non-Darcy and capillary number effects are included in the two-phase pseudo-pressure calculations. Bottom-hole back-pressure plots using two-phase pseudo-pressures can then be used to quantify productivity and mobility reductions and to separate the effect of the bank from other effects such as multi-layering, thus allowing identification of appropriate remediation measures. These results are verified with data from actual gas condensate and volatile oil reservoirs.