Evaluating Reservoir Production Mechanisms and Hydraulic Fracture Geometry in the Lewis Shale, San Juan Basin

Frantz, J.H.; Fairchild, N.R.; Dube, H.G.; Campbell, S.M.; Christiansen, G.E.; Olszewski, Adam J.

doi:10.2118/56552-ms

Cited by 10 publications

(19 citation statements)

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“…Matrix porosity (total) and effective gas permeability in the Lewis, as measured from sidewall and whole cores, range from 2% to 8% and 0.1 to 0.00001 md, respectively. 13 The average matrix gas porosity and permeability are 1.7% and 0.0001 md, respectively. The water saturation ranges from 20% to 100%, with an average of 70% over the entire Lewis interval.…”

Section: Reservoir Characterizationmentioning

confidence: 98%

“…A stress test was also performed after each slug test. In the SDW project, it was typical to perforate and test 6-8 layers with nitrogen 13,19 prior to the stimulation treatments. Each layer was broken down prior to the testing.…”

Section: Pre-stimulation Nitrogen Slug and Stress Testingmentioning

confidence: 99%

“…Since the perforations typically flow at < 20 Mscf/D, the slug tests are one of the only methods to obtain bulk permeability and reservoir pressure in a short time period. 13,19 Fig. 9 shows the falloff portion of the slug tests in SDW SJU 30-6 #27A as an example of the pressure data character.…”

Section: Pre-stimulation Nitrogen Slug and Stress Testingmentioning

confidence: 99%

“…We believe that this approach is the best tool to use in designing completions, stimulations, and optimizing well spacing, as well as forecasting future performance. 10,11,12,13,15,19 BR is continuing to collect this data in six additional SDWs. The modeling results indicate that we can accurately history match the pre-stimulation nitrogen slug test data, the post-stimulation pressure buildup data and the post-stimulation production performance from all the SDWs using the multi-layer simulation model.…”

Section: Production Rate and Eur From Spinner Survey Datamentioning

confidence: 99%

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The Lewis Shale, San Juan Basin: What We Know Now

et al. 2000

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Section: Reservoir Characterizationmentioning

confidence: 98%

Section: Pre-stimulation Nitrogen Slug and Stress Testingmentioning

confidence: 99%

Section: Pre-stimulation Nitrogen Slug and Stress Testingmentioning

confidence: 99%

Section: Production Rate and Eur From Spinner Survey Datamentioning

confidence: 99%

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The Lewis Shale, San Juan Basin: What We Know Now

et al. 2000

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“…To obtain the necessary pressure information, nitrogen slug and stress testing using both surface and memory readout gauges with downhole shut-in tools were introduced to the ConocoPhillips San Juan Business Unit (SJBU) in the late 1990s (Frantz et al 1999;Dube et al 2000). Multilayer pressure buildups were also introduced in the early 2000s (Frantz et al 2001).…”

Section: Multiple Diagnostic Fracture Injection Tests Performed Simulmentioning

confidence: 99%

A Method To Perform Multiple Diagnostic Fracture Injection Tests Simultaneously in a Single Wellbore

Martin

Cramer

Roberts

et al. 2013

SPE Production &Amp; Operations

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This paper presents a unique process for deriving reservoir properties (i.e., minimum horizontal stress, kh/u, and reservoir pressure) in isolated reservoir layers intersected by the same vertical wellbore. It is based on simultaneously performing multiple diagnostic fracture-injection tests (DFIT) with extended multiday shut-in periods using downhole shut-in tools and bottomhole memory gauges.A case study of 58 vertical wells completed in the Mesaverde and Dakota sandstones of the San Juan basin is used to describe and assess the above application. These intervals are gas productive, slightly to significantly subpressured, and possess a very low permeability pore network enhanced by natural fracture networks. As many as seven individual intervals per well were tested using the simultaneous process in an area spanning the entire San Juan basin. Large-scale, multistage hydraulic fracturing is necessary to establish commercial production from these intervals. The diagnostic tests were done before the large-scale fracture treatments, yet did not impede the subsequent implementation of the treatments. In the Dakota interval, the diagnostic testing results agreed well with the kh derived from post-fracture production analysis and led to a process of treatment design optimization. In the Mesaverde interval, less agreement was found between diagnostic-test and production-analysis results. Despite the lack of validation, fluid leakoff rates measured during the diagnostic testing provided insight into fracture half-length differences documented in a previous study of microseismic mapping. As part of the case study, procedural guidelines and best practices developed in the process of performing over 200 tests will be discussed.

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Modes of Shale‐Gas Enrichment Controlled by Tectonic Evolution

2018

Acta Geologica Sinica (Eng)

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The typical characteristics of shale gas and the enrichment differences show that some shale gases are insufficiently explained by the existing continuous enrichment mode. These shale gases include the Wufeng–Longmaxi shale gas in the Jiaoshiba and Youyang Blocks, the Lewis shale gas in the San Juan Basin. Further analysis reveals three static subsystems (hydrocarbon source rock, gas reservoirs and seal formations) and four dynamic subsystems (tectonic evolution, sedimentary sequence, diagenetic evolution and hydrocarbon‐generation history) in shale‐ gas enrichment systems. Tectonic evolution drives the dynamic operation of the whole shale‐gas enrichment system. The shale‐gas enrichment modes controlled by tectonic evolution are classifiable into three groups and six subgroups. Group I modes are characterized by tectonically controlled hydrocarbon source rock, and include continuous in‐situ biogenic shale gas (I1) and continuous in‐situ thermogenic shale gas (I2). Group II modes are characterized by tectonically controlled gas reservoirs, and include anticline‐controlled reservoir enrichment (II1) and fracture‐controlled reservoir enrichment (II2). Group III modes possess tectonically controlled seal formations, and include faulted leakage enrichment (III1) and eroded residual enrichment (III2). In terms of quantity and exploitation potential, I1 and I2 are the best shale‐gas enrichment modes, followed by II1 and II2. The least effective modes are III1 and III2. The categorization provides a different perspective for deep shale‐gas exploration.

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Evaluating Reservoir Production Mechanisms and Hydraulic Fracture Geometry in the Lewis Shale, San Juan Basin

Abstract: This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.

Cited by 10 publications

References 0 publications

The Lewis Shale, San Juan Basin: What We Know Now

The Lewis Shale, San Juan Basin: What We Know Now

A Method To Perform Multiple Diagnostic Fracture Injection Tests Simultaneously in a Single Wellbore

Modes of Shale‐Gas Enrichment Controlled by Tectonic Evolution

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