Jonah Field Research Articles

Rock typing of tight gas sands: A case study in Lance and Mesaverde formations from Jonah field

The Jonah field is one of the biggest tight gas sand fields in the Green River basin. Production profiles from its deeper sections show high liquid hydrocarbons close to the Pinedale anticline, especially in Mesaverde and Lance formations. To assess the potential of condensate production, new approaches for rock classification are needed to differentiate between discontinuous sandstone layers and the interbedded siltstones. A gamma ray cut off of 75 API has been defined to distinguish between sandstone and siltstone in logs and core samples in Lance and Mesaverde formations. Significant variation of porosity and permeability occurs within the sandstone zones. This variation warrants new rock typing approaches. We present rock typing for tight sandstones and siltstones with an understanding of petrophysical properties such as pore structure, porosity, permeability, and cementation.We studied 94 samples from the Mesaverde and Lance Formations with lithologies varying from clean sandstone to shale. X-ray diffraction (XRD) mineralogy, mercury injection capillary pressure (MICP), helium porosity and permeability were measured for all samples. NMR transverse relaxation times (T2) at 2 MHz were also measured for 10 water saturated samples. Nitrogen adsorption was performed on 11 samples from Mesaverde formation to determine pore volume and pore size distribution.MICP data are used to subdivide rocks into three groups based on pore throat size distribution: reservoir sandstones, non-reservoir sandstone and siltstone/mudstone. Dominant pore throat size for reservoir and non-reservoir sandstones are 400 and 100 nm, respectively. In order to apply pore throat size rock typing to downhole measurements, correlation between NMR pore size and MICP throat size is used. Pore size from NMR demonstrated equivalent behavior to pore throat size from MICP. The logarithmic mean values of T2 transverse relaxation times for reservoir, non-reservoir sandstone and siltstone/mudstone are 22.2 ms, 3.4 ms and 0.29 ms, respectively. Clear separation of reservoir sandstone, non-reservoir sandstone and siltstone is also seen based on pressure dependency of ultrasonic compressional and shear velocities during initial pressure loading. Reservoir sandstone demonstrates the highest compressibility. In addition, siltstone and mudstone were separated based on log differential pore volume distribution from N2 adsorption data.Based on pore size distribution data, four main rock types are identified in Lance and Mesaverde formations in Jonah field. Rock typing based on gamma ray and porosity logs can be considered as rock classification of end members. To capture transitional behavior in between end members, pore size distribution is needed in logging application. Since NMR T2 distribution show similar spectra to MICP throat size distribution, the rock typing technique can be applied using NMR log data. Separation of mudstone from siltstone can be used for identification of shale end points in log data.

C13 and Thomsen anisotropic parameter distributions for hydraulic fracture monitoring

Most shale reservoirs are described assuming transverse isotropy. A full characterization of such reservoirs requires the knowledge of six elastic parameters comprising, for instance, the density; P- and S-wave vertical velocities; and the three anisotropic Thomsen parameters [Formula: see text], [Formula: see text], and [Formula: see text]. For hydraulic fracturing monitoring purposes, the parameters [Formula: see text] and [Formula: see text] are typically estimated from perforation microseismic data by analyzing the variation with phase angles of the traveltimes of direct P-waves and direct SH-waves. The estimation of the Thomsen parameter [Formula: see text] is more challenging because most perforation microseismic data do not exhibit direct SV-waves to which the parameter [Formula: see text] is the most sensitive. A Bayesian inference method is proposed to estimate [Formula: see text] from traveltimes of secondary SV-waves observed on microseismic data. Because the interpretation of the physics underlying the observation of these secondary SV-waves is often not readily available for wellsite operations, a marginalization scheme is used to account for uncertainties associated with not knowing, or only partially knowing, the locations where they originated from. I determined the benefits of the proposed method by applying it to data sets collected in the Jonah field using a single monitoring well. The results revealed a significant variance reduction of more than 15-fold on the posterior probability distribution associated with [Formula: see text] when using the secondary-source SV-waves. Moreover, a more accurate estimate of the microseismically derived fractured volume is achieved with variance reduced by more than a factor of 75.

Distributions of air pollutants associated with oil and natural gas development measured in the Upper Green River Basin of Wyoming

Abstract Diffusive sampler monitoring techniques were employed during wintertime studies from 2009 to 2012 to assess the spatial distribution of air pollutants associated with the Pinedale Anticline and Jonah Field oil and natural gas (O&NG) developments in the Upper Green River Basin, Wyoming. Diffusive sampling identified both the extent of wintertime ozone (O3) episodes and the distributions of oxides of nitrogen (NOx), and a suite of 13 C5+ volatile organic compounds (VOC), including BTEX (benzene, toluene, ethylbenzene and xylene isomers), allowing the influence of different O&NG emission sources to be determined. Concentration isopleth mapping of both diffusive sampler and continuous O3 measurements show the importance of localized production and advective transport. As for O3, BTEX and NOx mixing ratios within O&NG development areas were elevated compared to background levels, with localized hotspots also evident. One BTEX hotspot was related to an area with intensive production activities, while a second was located in an area influenced by emissions from a water treatment and recycling facility. Contrastingly, NOx hotspots were at major road intersections with relatively high traffic flows, indicating influence from vehicular emissions. Comparisons of observed selected VOC species ratios at a roadside site in the town of Pinedale with those measured in O&NG development areas show that traffic emissions contribute minimally to VOCs in these latter areas. The spatial distributions of pollutant concentrations identified by diffusive sampling techniques have potential utility for validation of emission inventories that are combined with air quality modeling.

Lowered Tubing Offsets Field Production Decline

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 154394, ’Lowering Tubing in the Jonah Field Offsets Production Decline,’ by Chinenye E. Ogugbue, SPE, Cody R. Hopkins, Leah R. Greenly, SPE, Robert K. Wilson, and Gordon E. Gates, BP, prepared for the 2012 Americas Unconventional Resources Conference, Pittsburgh, Pennsylvania, 5-7 June. The paper has not been peer reviewed. Declining reservoir pressure and rate in the Jonah Field in the upper Green River basin in west-central Wyoming led to the common problem of liquid loading. Lowering the end of tubing (EOT) in more than 100 gas wells in the Jonah field enabled an average sustained production increase of approximately 105 Mcf/D, with an undiscounted payout of less than 12 months. In addition, for wells that have had the tubing lowered, the production-decline curves appeared to flatten out, offsetting anticipated double-digit decline. Introduction Discovered in the early 1990s, the Jonah field produces gas from the Lance formation, an extremely low-porosity, low-permeability, and fine-grained alluvial sandstone. The field is an overpressured area bounded on west and south by faults. The producing-formation thickness ranges from 2,000 ft updip to 3,500 ft downdip, at depths as shallow as 7,800 ft and as deep as 12,500 ft. Within this interval, the net-to gross-pay ratio varies from 25 to 40%. Sand bodies occur as both individual 9- to 15-ft-thick channels and as stacked-channel sequences, thicker than 200 ft in some places. Stacking of these alluvial-sand bodies resulted in an extremely heterogeneous reservoir in which reservoir sand bodies cover an areal extent of a few acres to as much as 640 acres. The field has been developed on 10-acre spacing. Wells are completed with eight to 16 hydraulic-fracturing stages, with each stage containing five to seven fluvial-sand-body channels. The Lance formation comprises the Lance Derbis Wedge, Lance Overpressure, Middle Lance, Jonah sands (Lance Jonah), Yellow Point sands, and the Wardell sands. The proven commercial gas-producing zones are the Lance Overpressure through the Wardell. BP operates 262 wells in the Jonah field. The wells have total depths ranging from 10,500 to 12,800 ft, with an approximately 3,500-ft vertical section of thick continental deposit composed of fluvial sandstones, back-swamp shales, coaly shales, and thick braided-stream sandstones. Porosity ranges from 8 to 10%, with permeability equal to 1 to 10 d. The average initial 30-day production was 1.5 MMcf/D. The aver-age condensate yield is 8.5 bbl/MMcf, and the water yield is 5–10 BW/MMcf.

Channel Fracturing - Paradigm Shift in Tight Gas Stimulation

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140549, ’Channel Fracturing - A Paradigm Shift in Tight Gas Stimulation,’ by J. Johnson, SPE, M. Turner, SPE, and C. Weinstock, SPE, Encana; and A. Pena, SPE, M. Laggan, SPE, J. Rondon, and K. Lyapunov, Schlumberger, prepared for the 2011 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 24-26 January. The paper has not been peer reviewed. The hydraulic-channel-fracturing technique relies on the engineered creation of a network of open channels within the proppant pack, providing highly conductive paths for fluid flowing from the reservoir to the wellbore. The Lance formation in the Jonah field near Pinedale, Wyoming, was selected for this study. Results indicate that implementation of the channel-fracturing technique increased initial gas production and estimated recovery over conventional fracturing methods. Positive features during this campaign included reduced net-pressure-increase estimates from pre- and post-fracture-treatment shut-in-pressure measurements, reduced tendency for vertical fracture growth, and elimination of near-wellbore screenouts. Introduction Natural gas plays a major role in the assortment of energy resources that sustain the USA. The imbalance between future energy demands and reduced availability of gas from conventional sources dictates the need to increase gas recovery from unconventional sources such as tight gas reservoirs, shale-gas reservoirs, and coal seams. Hydraulic-fracturing treatments in tight gas formations during the 1970s consisted of pumping large quantities of a propping agent and carrying gelled fluids and emulsions at pressures in excess of the formation-fracturing pressure. Beginning in the 1980s, this fracturing technique included various combinations of nitrogen gas and/or liquid carbon dioxide pumped in combination with fluid and proppant for stimulation purposes. Low-viscosity slickwater treatments, in which proppant is pumped at low concentrations within a high-rate water stream, became popular in the 1990s for stimulating tight gas reservoirs. All these techniques rely on filling the fracture with the propping agent to maintain an open fracture. The proppant pack placed within the fracture also serves as a conductive medium for gas flow to reach the wellbore. The effective area of the fracture covered by proppant varies according to the technique used. Typically, completion efficiency is low for slickwater treatments, and it often improves with the use of viscous carrying fluids and fibers, among other methods.

Development of a Calibrated Fracture-Growth Model and Automated Staging Routine for the Jonah Field

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 116304, ’Development of a Calibrated Fracture-Growth Model and Automated Staging Routine for the Jonah Field,’ by Scott Malone, SPE, and Mark Turner, SPE, EnCana Oil and Gas; Mike Mayerhofer, SPE, Pinnacle; Neill Northington, SPE, Carbo Ceramics; and Leen Weijers, SPE, Pinnacle, prepared for the 2009 SPE Rocky Mountain Petroleum Technology Conference, Denver, 14-16 April. An important challenge in the Jonah field in Wyoming is obtaining effective fracture-height coverage over the entire 2,800+ ft Lance formation. A calibrated fracture model was developed for the field that ties log analysis to the fracture-growth behavior that was mapped by use of direct fracture-mapping technologies and to the net-pressure response measured during propped-fracture treatments. These improvements in predictive-modeling capabilities have led to better insight into fracture-growth behavior in the Lance formation. A 3D fracture-growth model was modified to determine perforation strategies and fracture-treatment schedules in a semi-automated process. Introduction The formation comprises a stacked sequence of 20 to 50 fluvial-channel sands interbedded with associated overbank-siltstone and floodplain-shale deposits. Within this interval, the net-to-gross ratio varies from 25 to 40%. Sandstone bodies occur as individual 10- to 25-ft-thick channels and as stacked-channel sequences greater than 200 ft in some cases. The formation is overpressured and generally exhibits a net-pay thickness averaging 500 ft. The discontinuous lenticular sand bodies generally are aligned northwest/southeast, but sandstone-body geometries are largely uncertain. The Jonah field covers approximately 23,000 acres and has estimated reserves of 15.2 Tcf of natural gas. The average permeability from all diagnostic fracture-injection tests (DFITs) in the field is 0.024 md. However, the accepted permeability averages 0.01 md. Between November 2002 and September 2004, a 630 fracture treatments were mapped with surface-tilt-meter mapping (STM), 145 treatments were mapped with microseismic mapping (MSM), and 94 treatments were mapped with downhole-tiltmeter map-ping. A total of 130 surface tiltmeters were installed in shallow 40-ft holes across the field, enabling most propped-fracture treatments in various test areas to be mapped during that time period. In February 2008, another 16 fracture treatments were mapped with MSM along the northern downdip area of the field to verify whether the lessons learned in the southern part of the field could be extended to other areas. Fracture-Mapping Results Fracture Orientation and Complex-Fracture Growth. Approximately 75% of all fracture treatments in the field show a dominant fracture azimuth of N45°W, while a quarter of the treatments result in a primary fracture azimuth of N45°E. Approximately half of the fracture treatments consistently show a secondary orthogonal-fracture orientation resulting in a crosscutting-fracture network. The third occurring fracture orientation is horizontal, which is most likely associated with the debonding of bedding planes. This mechanism could also be responsible for fracture-height containment.

Constraining 3D facies modeling by seismic-derived facies probabilities: Example from the tight-gas Jonah Field

Seismic reservoir characterization is usually based on the interp retation of seismic attributes that relate to the geological feature or reservoir property of interest. If we are interested in fault geometries, a variety of geometric attributes can be used to map the details of fault distributions and constrain discontinuities and flow barriers in geological and flow-simulation models. If we are interested in reservoir properties, however, the usual approach is to estimate seismic attributes that are qualitatively related to such properties. The interpretation of the attribute focuses on the identification of “good” and “bad” areas depending on how the attribute relates to the property of interest.

Design through interpretation of a very large 3D VSP in a complex area in Jonah Field, Wyoming

In the spring of 2005, EnCana Oil & Gas (USA) proposed the acquisition of a 3D VSP data set in a well later drilled in a complex compartmentalized portion of the Jonah gas field in Wyoming. Development of this area would benefit from the greater reliability of structural and stratigraphic interpretation enabled by the increased resolution of this 3D VSP. Figure 1 illustrates the acquisition geometry. Seismic data are recorded by downhole geophones at the center of ap-proximately 1400 source points. Surface source point signals are collected by a receiver array in the borehole. The resulting 6.5 mile2 survey was designed, permitted and acquired within a nine-month period in 2005. Innovative design and acquisition techniques led to successful acquisition on time and within budget.

Infill well evaluations of Jonah Field tight gas: characterization and simulation of complex architectural elements

This paper summarizes recent reservoir characterization and simulation studies performed in the Jonah Field, one of the most prolific natural gas fields in the Rocky Mountain region of the United States. The goal of the studies was to integrate geology, petrophysics, 3D seismic, and engineering data into 3D geologic and engineering models to evaluate infill well development in different regions of the field. This article shows how variations in channel development and thickness have a direct impact on gas recovery and optimal well spacing for different areas of the field. We also show that these channels can be mapped with the help of attributes inverted from pre-stack seismic data.

The Effect of Completion Methodologies on Production in the Jonah Field

Summary Improvements in completion technology have continued to increase the industry's ability to economically extract hydrocarbons from very low permeability reservoirs. The Jonah field in southwest Wyoming is a classic example of a reservoir commercialized with newer completion technology. The Lance formation in the Jonah field consists of several hundred feet of stacked lenticular sands with a reservoir permeability to gas of less than 10 μdarcy, requiring hydraulic fracturing to be economic. Completion techniques have evolved over the years. In the past 4 years, two techniques have emerged as the predominant completion methods—induced stress diversion and flow-through composite fracture plugs. This study evaluates these different techniques with spatial sampling to compare each well to its offset wells and to identify the completion scheme that yields the best results on cumulative production. From this study, a clear best practice for completing wells in the Jonah field to maximize production was determined.

ABSTRACT: Jonah Field Area: Seismic Coherency Cube Technology Used to Define Trap Boundaries and Stratigraphic Features

ment wells at Jonah Field. Jonah Field, Sublette County, Wyoming, is expected to produce at least 1.5 TCF of natural gas from lenticular, over-pressured, tight formation gas fluvial sandstones of the Cretaceous-age Lance Formation. Depth of production is 7,500 to 12,400 feet and the gross producing interval is 1500 to 3200 feet. Jonah was indicated to be a significant field in early 1993 (Robinson, 2000) and now produces more than 400 MMCFD from more than 200 wells (Fig. 1). In-fill drilling on 40-acre spacing has been underway since mid-2000. Entrapment may result from a combination of dip reversal and fault zone deformation associated with faults that intersect up dip to form a wedge-shaped compartment. Apparent throw on the bounding faults is variable, but commonly is less than 200 feet.

Abstract: Jonah Field - A new TCF gas field in the Green River Basin, Wyoming

Abstract: Jonah Field - A new TCF gas field in the Green River Basin, Wyoming

Abstract:  Jonah Field: A Shallow Sweetspot in the Basin-centered Gas Accumulation of the Northern Green River Basin 

Abstract:  Jonah Field: A Shallow Sweetspot in the Basin-centered Gas Accumulation of the Northern Green River Basin 

Abstract: Evolution of Completion and Fracture Stimulation Practices in the Jonah Field, Sublette County, WY 

Abstract: Evolution of Completion and Fracture Stimulation Practices in the Jonah Field, Sublette County, WY 

Jonah Field, Sublette County, Wyoming: Gas Production from Overpressured Upper Cretaceous Lance Sandstones of the Green River Basin

Jonah field, located in the northwestern Green River basin, Wyoming, produces gas from overpressured fluvial channel sandstones of the Upper Cretaceous Lance Formation. Reservoirs exist in isolated and amalgamated channel facies 10-100 ft (3-30 m) thick and 150-4000 ft (45-1210 m) wide, deposited by meandering and braided streams. Compositional and paleocurrent studies indicate these streams flowed eastward and had their source area in highlands associated with the Wyoming-Idaho thrust belt to the west. Productive sandstones at Jonah have been divided into five pay intervals, only one of which (Jonah interval) displays continuity across most of the field. Porosities in clean, productive sandstones range from 8 to 12%, with core permeabilities of .01-0.9 md (millidarcys) and in-situ permeabilities as low as 3-20 µd (microdarcys), as determined by pressure buildup analyses. Structurally, the field is bounded by faults that have partly controlled the level of overpressuring. This level is 2500 ft (758 m) higher at Jonah ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.Grateful acknowledgment is made to Snyder Oil Corporation and Ron Finch, Integrated Petroleum Technologies, for figures and data used in this article. Thanks also to Floyd Bardsley for artwork.1Petroleum Consultant, 1511 18th Avenue East, Seattle, Washington 98112. 2Snyder Oil Corporation, 1625 Broadway, Suite 220, Denver, Colorado 80202. Send reprint requests to AAPG Publications Manager, P.O. Box 979, Tulsa, Oklahoma 74101-0979. Tcf = trillion cubic feet; Gcf = billion cubic feet; Mcf = million cubic feet; kcf = thousand cubic feet.

Abstract: Electrical Resistivity Image Reservoir Description of the Lance Formation, Jonah Field, Sublette Co., Wyoming 

Abstract: Electrical Resistivity Image Reservoir Description of the Lance Formation, Jonah Field, Sublette Co., Wyoming 

Abstract: Reservoir Lithofacies in the Lance Formation, Jonah Field, Sublette Co., Wyoming 

Abstract: Reservoir Lithofacies in the Lance Formation, Jonah Field, Sublette Co., Wyoming 

Abstract: A Structural Model for Shallower Emplacement of Gas in Overpressured Basin Centers: Jonah Field as a Previously Undetected Abnormally Pressured Structural Trap 

Abstract: A Structural Model for Shallower Emplacement of Gas in Overpressured Basin Centers: Jonah Field as a Previously Undetected Abnormally Pressured Structural Trap 

Abstract: Structural Geology of Jonah Field as Determined from Subsurface Geology and 3-D Seismic 

Abstract: Structural Geology of Jonah Field as Determined from Subsurface Geology and 3-D Seismic 

Integrated Reservoir Description and Analysis of the Lance Formation at Jonah Field, Sublette County, Wyoming: ABSTRACT

Log, core, and production data from the 16 wells in Jonah field have been used to characterize sandstone reservoirs in the Lance Formation (Cretaceous) in the northern Green River basin. The Lance Fm. is composed of 2500 feet of heterolithic fluvial strata that were deposited on a broad alluvial plain. Sandstones were deposited in east- flowing channels 10-20 feet deep and 150-4000 feet wide; some amalgamated sandstone intervals are >100 feet thick and over a mile wide. Fluvial architecture varies from isolated meandering river deposits to amalgamated braided river deposits. Sandstones are dominantly composed of detrital chert and quartz grains. The Lance Fm. has been divided into several informal pay intervals that have different reservoir character and performance. Wardell interval sandstones produce gas in eight wells and are poor reservoirs due to fine grain size, high clay and cement content, and greater depth. Yellow Point interval sandstones have shown average performance in five wells. The Jonah interval produces in 10 wells and is the most prolific pay zone with up to 150 net feet of sandstone having core porosity of 8-12% and permeability of .01-0.9 mD. Upper and middle Lance sandstones have better than average performance from five wells. Allmore » pay intervals require greater than 8% porosity and less than 35% water saturation. Pre-frac pressure build-up analysis indicates in situ permeabilities of 3-20 microdarcys and suggests that fractures are a significant contributor to deliverability. Estimated reserves of 0.4-4.0 BCFG/well are based on decline curve analysis. Liquid yields vary from 6-86 BO/MMCFG and increase with depth. Pressure gradients range from .55 to .59 psi/ft. Reservoir overpressure is a result of continuous migration of hydrocarbons into available pore space via microfracture seepage.« less