The success of most fracture treatments is primarily dependent on the ability to evaluate the characteristics and critical mechanisms that control how a formation hydraulically fractures. By developing an understanding of the mechanisms, it is possible to make the necessary improvements to ensure optimum proppant placement and therefore maximize economic results. This discussion presents a simple, low cost method for improving the overall fracture geometry and reducing the risk of premature screenouts. Dramatic improvements in near-wellbore tortuosity and improvements in proppant placement can be achieved by maximizing the viscosity of fluid that is used to initiate the fracture and carry proppant through the near-wellbore region. Using the approaches presented, it has been possible to eliminate premature screenouts and improve the overall proppant placement in many different environments.

This paper is a case history describing fracture optimization of low-permeability highly-stratified stacked turbidite sandstone reservoirs of the B interval of the Elk Hills Field. The occurrence of high-permeability, high-pressured water saturated sands immediately above and/or below the objective oil sands poses a major challenge. Integration of improved petrophysical understanding, geoscience techniques, hydraulic fracture model calibration and on-site, real-time execution has achieved a two-fold oil production increase in the south east nose area of the field while limiting water production to a 40% increase. Downhole tiltmeter measurements are incorporated to calibrate the fracture model and limit fracture height growth, thus regulating fracture conductivity to the oil saturated reservoirs, and minimizing contact with the adjacent wet zones. To date, results from surface tiltmeter1 measurements completed during twenty six fracture stages have been used with the downhole tiltmeter2 data and reservoir characterization to optimize the ongoing redevelopment from a peripheral waterflood to a pattern flood. Introduction Elk Hills Oil Field is located on the west side of the southern San Joaquin Valley of central California. It is positioned 20 miles southwest of Bakersfield and approximately 10 miles northeast of Taft (Figure 1). The Field was designated as the Naval Petroleum Reserve No.1 in 1912 to provide oil to the Navy in the event of a national emergency. Elk Hills Field produces oil and gas from several reservoir intervals highlighted on the stratigraphic column, (Figure 2). Production depths range from 1,100 to 9,500 ft, TVD. Initial production was established in 1911 from Pliocene age sands of the Shallow Oil Zone where production is related to a broad surface anticline with prominent topographic relief (Figures 1–2). In 1941, Stevens sands of the upper Miocene Montery Formation were found to be productive on the 31S structure, the largest of three deep structural anticlines at Elk Hills (Figures 2–3). Primary Stevens reservoirs on the 31S feature include the Main Body B (MBB) and Western 31S (W31S) of the B interval, and the younger, prolific 26R pool (Figures 3–5). Secondary objectives include sands in the B Shale zone and the siliceous shales or sands in the NA and CD Shale zones that lie above and below the B interval, respectively. MBB/W31S reservoirs occur at an average depth of 6,500 ft and exhibit 2,800 ft of vertical closure between the up-dip pinchout of the sands near the anticlinal crest and the Oil-Water Contact at −6,800 ft, subsea depth. These zones have abnormal reservoir pressure (0.50 psi/ft), good permeability (10 to 250 md, air permeability) and thick net pay development (300 to 500 ft). MBB production was held in reserve with only periodical tests until the energy crisis of the mid-1970's. In 1976, the U.S. Department of Energy (DOE) began producing the interval at initial rates ranging from 500 to 2000 BOPD per well.

Focused modifications in drilling, reservoir, and completion engineering from 2009 to the present have improved Bakken, specifically the South Antelope Field, production as much as 50% to 75%. To achieve these results, Helis Oil and Gas Co., LLC formed a multi-disciplinary team in 2008 which it tasked with evaluating and overhauling its completion approach. Pre-2008 completions followed conventional wisdom: target the Middle Bakken Formation between the Lodge Pole and the Three Forks Formations. Pre-2009 wellbore constructions included "kick outs" (i.e., multi-lateral), open-hole completions; short laterals; single-stage ported subs; sliding sleeves; and long stage intervals and were erratic and inconsistent. The designs and procedures resulted in a high percentage of pre-mature screenouts. In addition, the production responses on these Middle Bakken completions averaged 330 bopd with an estimated ultimate recovery (EUR) of 300 MBOe. During the pre-2009 period, 3 Three Forks were completed and these wells produced on average 550 bopd. After evaluating the pre-2009 results, the team recommended 10 changes: (1) change landing target to the Three Forks; (2) increase lateral lengths ~2x from "640's" to "1280's"); (3) increase formation contact (completion method, stage lateral length and, perforation spacing/density); (4) refine pump-down operations; (5) implement critical fracturing mechanisms diagnosis; (6) incorporate proppant selection (ceramic versus sand); (7) refine flush procedure to include monitoring and assure consistency; (8) integrate on-site, real-time pressure management and proppant schedule including proppant slugs, altered mesh types, and adjusted ramp schedule; (9) adjust treatment fluid design (25-lb gel loading instead of 40-lb gel loading); and (10) implement flowback and flowrate control. Implementing these recommendations, Helis deviated from conventional Williston Basin philosophy and drilled 30 "1280's" in 2010-2012. These wells resulted in ~1,500 bopd with a maximum of 2,500 bopd and EUR's of ~1,200 MBOe. They are among the best wells in the Williston Basin. In comparison, direct offset well EUR's averaged less than 750 MBOe. The success of these wells is not the result of one breakthrough but rather the result of sound changes to engineering techniques that were carried out systematically. Applying these engineering practices, maintaining strict adherence to recommended practices, and not making drastic, unfounded changes ultimately optimized production in this Bakken project.

Summary Stress testing (micro-hydraulic fracturing) is recognized by the petroleum industry as the most direct method of determining the minimum in situ (closure) stress for a given reservoir rock and the surrounding formations. In general, it is variations of in situ stress between formations that dominates hydraulic fracture height growth and overall fracture geometry. Misleading interpretations of stress test data (cased or open hole) can lead to significant errors m the prediction of stress contrast between the producing and bounding rock layers as well as an erroneous estimation of closure stress in the productive interval. In either case, hydraulic fracture treatment designs based on this information may not be designed optimally and the subsequent interpretation of the fracturing treatment pressure response may not be correct. This paper presents an evolutionary approach in the analysis of stress test data which leads to more consistent results that relate directly to actual fracture treatment pressure responses. Although the emphasis in this paper is on cased hole stress test data interpretation, the methodology presented is also applicable to open hole stress testing and larger scale pump-in/shut-in (i.e. calibration or minifrac) pressure falloff responses. Introduction The interpretation of stress test data is generally considered the basis by which other stress interpretation techniques and pressure analysis methods are compared and/or calibrated. Unfortunately, the interpretation of stress data does not appear to be as straight forward as initially perceived. Many of the same phenomena observed during large scale pump-in/shut-in and pump-in/flow-back treatments (i.e. minifracs or calibration treatments) as discussed by Nolte also complicate the analysis of stress test data. Some of these phenomena include:continued fracture tip extension;pressure dependant leakoff; andadjacent barrier effects. Other effects which tend to complicate analyses include:near-wellbore closure;multiple fractures; andnear-wellbore pressure drop (i.e. tortuosity). Generally, a simplistic approach to analyzing stress test data (especially in cased hole) is pursued without regard to any of the previously mentioned phenomena. Ironically, these phenomena may have a larger impact on the interpretation of stress test data than on "minifrac" data. Standard modern well test pressure transient analysis techniques are the most commonly used methods for analyzing pressure falloff data from stress tests.