Water injection and reservoir fluid production result in poroelastic stress changes that can dramatically alter the created fracture geometry on infill wells. This basic conclusion is not new. It has been documented in many different environments, and is supported by theoretical modeling. However, this paper presents for the first time a large data-set of 76 fracture treatments in a concentrated area that not only shows stress reorientation, but also shows how fracture reorientation depends critically on the pattern of injectors and producers and their interaction. This knowledge can be used to improve recovery in water injection projects that depend on closely spaced fractured wells.

Data is presented from 76 fracture stages in 16 infill wells completed within a one-year period in Chevron’s Lost Hills diatomite waterflood. Surface tiltmeter fracture mapping determined the fracture orientation (azimuth and dip) of the induced fractures, consisting of a vertical fracture component and a secondary sub-horizontal fracture component. This dataset clearly shows that the interaction between injectors (located in a line along preferred fracture azimuth) and producers results in a large-scale stress perturbation, producing a “room-and-pillar” stress structure. Both the fracture azimuth and the degree of secondary sub-horizontal fracturing are controlled by the location of infill wells with respect to nearby injector wells. Infill wells “inline” with injector wells yield fractures that grow close to the initial preferred fracture orientation. In contrast, infill wells that are “offset” from the line of injector wells yield highly variable fracture azimuths (often rotating towards injector wells) and greatly increased secondary sub-horizontal fracturing – both of which raise the risk of “short-circuiting” waterflood sweep. The data is presented and phenomenologically explained. A geomechanical model explains the observed stress changes, allowing predictive modeling of various infill-drilling scenarios in waterfloods to optimize recovery.

Refracturing can be used to increase production in poorly fractured wells. A different application of this technology is to refracture wells with strong initial fractures. In this paper, we provide evidence of increased production due to refracturing two tight gas wells having deeply penetrating initial fractures. Surface tiltmeter measurements show refracture orientations at oblique angles to the azimuth of the initial fractures.

Conventional wisdom regarding fracture orientation 1 of steam fractures is that they grow along the same orientation as “typical” propped fracture treatments – i.e., perpendicular to the least principle stress direction. However, direct measurements (utilizing surface tiltmeter fracture mapping) show that the orientation of steam-induced fractures is very different from propped fractures. Steam fractures have been observed to grow predominantly along two distinct planes that are oriented 45° with respect to the preferred fracture plane. These two planes coincide with the planes of maximum shear stress. Steam fracture reorientation toward these two planes has thus far been directly observed in the South Belridge, Lost Hills, and Cymric Fields in the San Joaquin Valley in California.

The measured data also shows that the fracture orientation is sensitive to the injection rate. Above a “critical” rate (which most likely depends on horizontal stress bias, shear frac conductivity and fluid viscosity) fractures grow perpendicular to the minimum principle stress. Below this critical rate, however, fracture growth is along the two distinct maximum-shear orientations. Steam injection wells are especially vulnerable, as steam injection rates are generally low in comparison to propped fracture treatments. The proposed mechanism for steam fracture reorientation that we present in this paper is pore pressure elevation along a direction of enhanced permeability along shear fractures ahead of the fracture tip, which causes the preferential fracture growth direction to change along the direction of maximum shear stress.

Although fracture reorientation can provide an increase in reservoir access and production rates in areas where the “huff and puff”-technique is used, reorientation is detrimental for steamfloods, as “short-circuiting” may result and reserves may be bypassed.

Hydraulic fracture orientation is critical to both primary and secondary oil recovery in low-permeability reservoirs. Incomplete and often overlapping drainage patterns under primary recovery, as well as inefficient sweep and premature water (or steam) breakthrough under secondary recovery are some of the common production problems that often result from hydraulic fracture reorientation. Often, hydraulic fracture orientation is measured on a few wells, and then generalized across the entire field under development. This characterization of regional fracture (stress) orientation is then assumed constant over the development life of the field. A wealth of recent observations have definitively shown that fracture (stress) orientation in low-permeability reservoirs can be profoundly affected by production activities.

Hydraulic fracture reorientation has been observed on dozens of staged fracture treatments (in several fields) under both primary and secondary recovery. A summary of collected field data from three extensive field studies is presented. The production impact of fracture reorientation on both primary and secondary recovery schemes is addressed; and strategies are presented which utilize the recent findings for both enhancing primary recovery and mitigating some common problems with secondary recovery.

The discussion of reorientation mechanisms is greatly enlightened by recent data which reveals a startling correlation between observed fracture reorientation and indirect measurements of reservoir compaction.

Waterflooding of California's diatomite reservoirs has heen extensively employed for two reasons: (1) to increase total recovery, and (2) to mitigate the potentially catastrophic effects of reservoir compaction and the resulting surface subsidence. Waterflooding has typically striven to replace each barrel of produced fluid with a barrel of injected water in order to achieve "zero net voidage." The extremely low permeability of the diatomite reservoirs, however, results in the generation of very significant reservoir pressure gradients during waterflooding, even under zero net voidage conditions. These extreme gradients in reservoir pressure, together with the reservoir compaction, result in significant changes in the local reservoir stress field. These local stress perturbations can, in turn, result in reorientation of hydraulic fractures on infill wells and possibly contribute significantly to the potential for wellbore casing failure.

This paper summarizes the (preliminary) findings from extensive field studies of hydraulic fracture orientation in diatomite waterfloods and related efforts to monitor the induced surface subsidence. Included are case studies from the Belridge and Lost Hills diatomite reservoirs. The primary purpose of the paper is to document a large volume of tiltmeter hydraulic fracture orientation data that demonstrates waterflood-induced fracture reorientation-a phenomenon not previously considered in waterflood development planning. Also included is a brief overview of three possible mechanisms for the observed waterflood fracture reorientation. A discussion section details efforts to isolate the operative mechanism(s) from the most extensive case study, as well as suggesting a possible strategy for detecting and possibly mitigating some of the adverse effects of production/injection induced reservoir stress changes - reservoir compaction and surface subsidence as well as fracture reorientation.

Refracture treatments have been effectively used for production enhancement fix decades. Typical motivations fix refracture treatments include: restoring the fracture conductivity to the (possibly) "damaged" proppant pack of the initial fracture treatment; achieving a longer propped fracture by placing a much larger volume of proppant or simply achieving a more effective proppant pack through the use of vastly improved fracture design procedures. This paper describes tiltmeter hydraulic fracture mapping field studies which conclusively document a significant additional motivation for refracture treatments, namely: refracture reorientation. Reorientation of propped refracture treatments allows contact with undepleted reservoir from older existing wellbores, which can restore production to near initial rates.

Chevron has performed over 200 refracture treatments m the diatomite reservoir within the Lost Hills field. Most treatments have consisted of refracturing intervals originally stimulated with less than adequate fluid and proppant volumes to efficiently deplete the reservoir. Many of these refracture treatments show production and pressure responses similar to new development wells completed in virgin" reservoir. Recently, from 1990 to 1993, four new wells (post 1986) with modern initial fracture treatments were refractured in the same intervals with treatments similar (fluid and proppant volumes) to the original fracture treatments. All wells responded with post refracture production response equal to or slightly less than that of the original treatments. On the average these wells showed production increases of 50 BOPD over the previous daily rates of approximately 10 BOPD.

An effort began in 1993 to investigate possible reasons for the apparent "virgin" production response that resulted from the refracture treatments. A number of potential mechanisms were considered, including dramatic fracture conductivity degradation of the original propped fracture treatments; greatly enhanced fracture length growth upon refracturing; and stress change induced reorientation of the refracture treatments along a different fracture plane than the original fractures. This latter mechanism was considered the most likely mechanism and a program was designed to gather the necessary data for positive determination. Because Chevron had previously utilized tiltmeter fracture mapping on over 100 propped fracture treatments in the Lost Hills Diatomite, there existed ample original fracture treatment orientation data for comparison with fracture mapping data from refracture treatments.

In the Spring of 1993 tiltmeter fracture mapping was performed on five refracture treatments. All five of the refracture treatments propagated along a significantly different orientation than the original fracture treatments in these wells. Refracturing along a different fracture plane from the original fracture plane has dramatic implications for production strategies of both primary and secondary recovery. The tiltmeter fracture mapping results, production data, calculated reservoir stress changes, and proposed mechanism for refracture reorientation are all presented in the paper.

In order to increase gas production in an under-producing formation, the German utility/energy company RWE-DEA stimulated the Wardboehmen Z1 well with a propped fracture treatment on December 6, 1991. Two days prior to the main fracture treatment, a step-rate test and mini-fracture were pumped for the purpose of evaluating more accurately the characteristics of the reservoir, including closure stress, leak-off rates, and permeability (and stress) profile. This information was then used to substantially improve the originally proposed design, provided by the service company, in order to create an effective/optimal propped fracture in this reservoir, incidentally also producing major savings in job cost. For the first time in Germany, electronic bottomhole pressure-measuring equipment with surface readout was used, during the minifrac. Availability of the bottomhole pressure data in the minifrac and repeated abrupt flow-rate changes, including shut-ins of about one minute, during both the minifrac and main fracture treatment allowed realistic simulation of fracture development with an on-site real-data 3D simulator. It was possible to determine the continually changing friction losses in the near-wellbore vicinity of the perforations: this tortuosity was very high initially but reached acceptable values after pumping the re-designed pad volume. This finding was important because it minimized the risk of a premature near-wellbore screen-out resulting from the planned proppant concentrations, up to 1,250 g/l (10 ppg). The fracture treatment led to a consistent four-fold increase in the gas production rate. This success was due, at least partly, to careful planning and use of novel technology in the fracture treatment, which allowed the on-site determination of actual reservoir conditions, with growth influenced by extremely variable permeability as against idealized models used for initial design.

An experimental study has been carried out to investigate the influence of the cementing chronology. That is to say, cementing of a perforated casing in a stress-free borehole or a loaded borehole resulted in a difference in near wellbore fracture geometry.

Starter fractures, propagating into multiple fractures, were observed when the casing was set and cemented in a stress-free borehole. Cementing the casing in a stressed borehole resulted in a continuous fracture along the wellbore, which sometimes ignored the perforations. Therefore, hydraulic fracturing experiments with the aim to represent field situations should be carried out when the casing is cemented in a stressed borehole.