Some History Cases of Long-Term Linear Flow in Tight Gas Wells

Arevalo-Villagran, J.A.; Wattenbarger, R.A.; Samaniego-Verduzco, Fernando

doi:10.2118/06-03-01

Cited by 11 publications

(7 citation statements)

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“…Long-term linear flow in a large number of wells in tight or shale gas has been observed as early as 1976 (Bagnall and Ryan 1976 causes this phenomenon. Several authors have shown that this linear flow exists in any type of fractures whether they are infinite- (Agarwal et al 1979) or finite-conductivity (Cinco-Ley et al 1978;Samaniego 1981a, 1981b), single or multistage Wattenbarger 2010), hydraulic (Arévalo-Villagrán et al 2001), or natural fractures (Arévalo-Villagrán et al 2006). The difference among these models is the length of this transient linear-flow regime.…”

Section: Methods Developmentmentioning

confidence: 99%

Rate-Decline Analysis for Fracture-Dominated Shale Reservoirs

Duong

2011

SPE Reservoir Evaluation &Amp; Engineering

261

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Traditional decline methods such as Arps' rate/time relations and their variations do not work for wells producing from supertight or shale reservoirs in which fracture flow is dominant. Most of the production data from these wells exhibit fracture-dominated flow regimes and rarely reach late-time flow regimes, even over several years of production. Without the presence of pseudoradial and boundary-dominated flows (BDFs), neither matrix permeability nor drainage area can be established. This indicates that matrix contribution is negligible compared with fracture contribution, and the expected ultimate recovery (EUR) cannot be based on a traditional concept of drainage area. An alternative approach is proposed to estimate EUR from wells in which fracture flow is dominant and matrix contribution is negligible. To support these fracture flows, the connected fracture density of the fractured area must increase over time. This increase is possible because of local stress changes under fracture depletion. Pressure depletion within fracture networks would reactivate the existing faults or fractures, which may breach the hydraulic integrity of the shale that seals these features. If these faults or fractures are reactivated, their permeabilities will increase, facilitating enhanced fluid migration. For fracture flows at a constant flowing bottomhole pressure, a log-log plot of rate over cumulative production vs. time will yield a straight line with a unity slope regardless of fracture types. In practice, a slope of greater than unity is normally observed because of actual field operations, data approximation, and flow-regime changes. A rate/ time or cumulative production/time relationship can be established on the basis of the intercept and slope values of this log-log plot and initial gas rate. Field examples from several supertight and shale gas plays for both dry and high-liquid gas production, and for oil production were used to test the new model. All display the predicted straightline trend, with its slope and intercept related to reservoir types. In other words, a certain fractured flow regime or a combination of flow types that dominate a given area or play because of its reservoir-rock characteristics and/or fracture-stimulation practices all produce a narrow range of intercepts and slopes. An individualwell performance or EUR can be derived that is based on this range if the best 3-month average or the initial production rate of the well is already known or estimated. The results show that this alternative approach is easier to use, gives a reliable EUR, and can be used to replace the traditional decline methods for unconventional reservoirs. The new approach is also able to provide statistical methods to analyze production forecasts of resource plays and to establish a range of results of these forecasts, including probability distributions of reserves in terms of P90 (lower side) to P10 (higher side).

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Section: Methods Developmentmentioning

confidence: 99%

Rate-Decline Analysis for Fracture-Dominated Shale Reservoirs

Duong

2011

SPE Reservoir Evaluation &Amp; Engineering

261

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“…We use a linear flow model to couple fracture-reservoir gas flow because linear flow is the predominant flow regime in shale reservoirs with hydraulic fractures. Transient linear flow usually occurs in unconventional formations and may last for many years (Arevalo-Villagran et al 2006;Tabatabaie and Pooladi-Darvish 2017). The major reason is that linear flow is associated with hydraulic fractures, and the well-fracture geometry results in linear flow behavior (Arevalo-Villagran et al 2006).…”

Section: Fracture and Reservoir Modelsmentioning

confidence: 99%

Shale gas reservoir modeling and production evaluation considering complex gas transport mechanisms and dispersed distribution of kerogen

Zeng

Liu

et al. 2020

Pet. Sci.

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Stimulated shale reservoirs consist of kerogen, inorganic matter, secondary and hydraulic fractures. The dispersed distribution of kerogen within matrices and complex gas flow mechanisms make production evaluation challenging. Here we establish an analytical method that addresses kerogen-inorganic matter gas transfer, dispersed kerogen distribution, and complex gas flow mechanisms to facilitate evaluating gas production. The matrix element is defined as a kerogen core with an exterior inorganic sphere. Unlike most previous models, we merely use boundary conditions to describe kerogen-inorganic matter gas transfer without the instantaneous kerogen gas source term. It is closer to real inter-porosity flow conditions between kerogen and inorganic matter. Knudsen diffusion, surface diffusion, adsorption/desorption, and slip corrected flow are involved in matrix gas flow. Matrix-fracture coupling is realized by using a seven-region linear flow model. The model is verified against a published model and field data. Results reveal that inorganic matrices serve as a major gas source especially at early times. Kerogen provides limited contributions to production even under a pseudo-steady state. Kerogen properties' influence starts from the late matrix-fracture inter-porosity flow regime, while inorganic matter properties control almost all flow regimes except the early-mid time fracture linear flow regime. The contribution of different linear flow regions is also documented.

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“…This paper, and others, discusses the behavior of gas wells in long-term linear flow. Several mechanisms are presented that can lead to apparent linear flow behavior, including infinite conductivity fractures extending to the drainage area boundary, anisotropic reservoir system permeability (possibly caused by a directional fracture enhancement trend), or linear deposition channels (Arevalo-Villagran, et al, 2006;Ibrahim and Wattenbarger, 2006). While all of these are possible, for some reason the industry has, in general, taken the first cause (infinite conductivity fractures with no inflow beyond the fracture tips) as the reason for the presumed linear flow signature observed in some production analyses.…”

Section: Application Of the Linear Flow Modelmentioning

confidence: 99%

Economic Optimization of Horizontal Well Completions in Unconventional Reservoirs

Barree¹,

Cox

Miskimins³

et al. 2014

All Days

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Extrapolation of conventional paradigms to unconventional reservoirs can lead to disappointment and poor performance. Careful analysis of the reservoir and application of the correct stimulation design is critical when dealing with marginally economic developments. This includes adequate characterization of the reservoir and an understanding of the factors that control flow capacity and deliverability.One of the biggest practical problems with unconventional stimulation design optimization is estimating post-fracture rate, production decline and ultimate recovery. Without a realistic prediction of the decline resulting from a given completion it is impossible to assign value to one design over another and equally impossible to optimize the treatment for whichever goal is sought, either acceleration of recovery or increase in reserves.It is often the first -inadequate reservoir characterization -that leads to the second -unrealistic post-treatment predictions. For instance, assuming core-derived permeability fully represents the reservoir's total flow capacity or that stimulated reservoir volumes represent the effective producing volumes, can lead to incorrect diagnosis of the reservoir capability and consequently, lead to an inefficient treatment design. This paper presents methods for production forecasting that give reasonable post-treatment predictions that have been found useful for economic planning. The proposed methodology, backed by field observations and laboratory work, provides an economically viable plan for optimizing lateral length, fracture spacing, and treatment design. The methodology focuses on the post simulation effective reservoir volume. Results show that increasing apparent fracture length rarely impacts long term recovery. Likewise, adding more fractures within the same reservoir volume may increase early time production rate (IP) and decline rate, without contacting more reservoir volume or adding to long term recovery. Such practices lead to acceleration of reserve recovery, which has economic value and should be considered in the design process, but does not increase the well's ultimate recovery once a sufficient number of fractures are in place. The economically preferred completion designs may be more driven by the net present value derived in the first five years of production rather than focusing on 20-50 year EUR's. This period represents most of the useful economic life of the well, can be estimated more accurately from early performance and therefore is a good benchmark for completion optimization.

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Some History Cases of Long-Term Linear Flow in Tight Gas Wells

Cited by 11 publications

References 0 publications

Rate-Decline Analysis for Fracture-Dominated Shale Reservoirs

Rate-Decline Analysis for Fracture-Dominated Shale Reservoirs

Shale gas reservoir modeling and production evaluation considering complex gas transport mechanisms and dispersed distribution of kerogen

Economic Optimization of Horizontal Well Completions in Unconventional Reservoirs

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