CONNECTIVITY MAPPING IMPROVES UNDERSTANDING OF RESERVOIR CONTINUITY
Gordon E. Tinker
Tinker Petroleum Consultants Inc.
Houston
Walter R. Turpening
Yu-Taik Chon Reservoir Imaging Inc.
Stafford, Tex.
Connectivity mapping uses guided waves from crosswell seismology procedures to obtain a better understanding of reservoir trapping and production mechanisms.
An inadequate understanding is likely to leave significant amounts of oil in place even after primary and secondary recovery.
In complex areas, correlation of lithology and stratigraphy is difficult with existing surface and crosswell imaging techniques. Seismic data lack vertical resolution, and boreholes that are far apart are difficult to correlate.
Conventional reservoir characterization depends on indirect means such as geological correlations using well control and more direct means such as pulse tests, and radioactive or other injection tracers. Conventional methods may be more costly, require production or injection of fluids, or depend on monitoring fluid movement through the reservoir.
In many cases, these conventional procedures result in time delays or failure to acquire the desired information.
APPLICATIONS
Many companies are focusing on more detailed characterization and precise geologic definition of mature oil and gas fields.
Connectivity mapping can show the continuity of producing horizons with vertical resolutions of 3-5 ft. The wave guides, used in mapping these horizons, are formed when a low-velocity formation is embedded between two relatively higher velocity formations. Only about a 5-10% velocity contrast is needed for this wave guide effect.
Most reservoir rocks, because of porosity and permeability, act as excellent wave guides.
Seismic signals traveling as trapped waves in wave guides exhibit characteristic amplitude/frequency spectra that are dependent upon formation properties and the boundary configuration. A crosswell seismic source in one well and a number of receivers in another well provide the signals to map the connectivity (continuity) of the formation layers.
Typically the measurements are made at spacings of 2-5 ft over the target producing interval. Recorded data are processed to identify and analyze the guided waves before construction of the interval's connectivity map.
During drilling, a drill bit as a downhole seismic source is ideal for connectivity mapping because the bit generates a large amount of acoustic energy that can be detected several miles away by receivers in other wells. The connectivity of the producing and sealing formations between the well being drilled and the receiving wells can be mapped. Based on this information, drilling objectives can be finalized.
Connectivity mapping can be expected to increase hydrocarbon primary recovery and prevent the trapping of oil during waterfloods, gas injection projects, and other displacement processes. Reservoir characteristics that can be measured or determined using connectivity mapping include individual channels, natural fractures, intervals in horizontal and high-angle wells, continuity and barriers, and vertical permeability.
INDIVIDUAL CHANNELS
Complex channel sand reservoirs made up of meandering, braided, deltaic, distributary, or alluvial fan deposits require careful characterization to prevent trapping oil. Fig. la is a plan view of a stream network reservoir developed with 12 wells.
Connectivity mapping identifies the continuity between wells for each of the five zones. With proper choice of injection wells, this field can be waterflooded.
To optimize oil recovery, additional wells will be required in Zone C.
NATURAL FRACTURES
Natural fracture systems occur in mann, reservoirs, but they commonly occur parallel or perpendicular to faults, at the crest of structures, and in low-permeability rock. These fractures are high-permeability features that may control a natural or designed displacement process so that mapping them is essential for optimum oil recovery.
Fig. 1b is a plan view of an oil reservoir that shows the position of the existing wells relative to the natural fracture system.
Water injection should be normal rather than parallel to the fracture system. By injecting water into a fracture with no oil production, adjacent oil producing wells will be waterflooded efficiently.
One step in processing data for connectivity, mapping involves analyzing frequency spectra. These spectra contain information about the fractured intervals. The patterns for the formation are different when the crosswell survey is along instead of across the fractures.
The density of a fracture system can be determined by the frequency spectra relative amplitudes.
Horizontal or high-angle wells are commonly drilled to intersect a fracture network at right angles to drain the fractures and suppress gas or water coning by reducing the pressure drawdown in the fractures. Fig. 1c is a cross-section of a fracture system showing the optimum position of a high-angle well determined by connectivity mapping.
Operationally, connectivity mapping can be done between a number of wells. For example in Fig. 1b, to convert Well 4 into a horizontal well, crosswell surveys would be recorded between pilot holes for Wells 4 and 5, 6, 2, and 3. If the analysis indicates that the northwest direction is optimum, Wells 2, 3, and possibly 5 could be drilled horizontally in the same direction.
CONTINUITY AND BARRIERS
In reservoirs consisting of stream bed deposits, continuity can be limited by barriers, discontinuities, or partial barriers. Fig. 1d shows three types of barriers that could be identified by connectivity mapping. Geological correlation indicates that there is likely continuity between the source and receiver wells in all three sands.
In Case 1, the barrier is identified as a hard barrier with the two sands not in proximity,. In Case 2, the single sand contains a partial barrier of reduced connectivity. In Case 3, the two sands are separated by a soft barrier and are in close proximity.
To determine the possible location of an infill well to recover trapped oil, connectivity mapping could find the approximate location of a soft barrier between two wells. Case 3 shows this situation. The infill well should be located more than half way between the wells, closer to the receiver well.
Connectivity mapping can determine the continuity of a whole field with zone resolution of 3-5 ft by creating a seismic source in one well and locating receivers in the surrounding wells. The source can be in an existing well or the bit noise in an infill well being drilled (Fig. 1e). The same borehole seismic sources can be used in either perforated on nonperforated intervals.
A thinning (bottleneck) of the reservoir between two wells can be identified and approximately located by connectivity mapping. Fig. If shows the bottleneck caused by a channel filled with shale cuttings into a second stream bed.
Connectivity mapping does not require a perforated completion. Because most seismic sources do not require direct fluid contact with the formation fluids, the survey can be carried out in open hole, cased hole, perforated completions, or a mixture of these situations. This flexibility greatly increases the applications.
The relative porosity distribution of various reservoir layers can be determined if a wave guide is created between two wells by a higher porosity interval being bracketed by layers of lower porosity.
For a waterflood plan, it is necessary to identify the orientation of all barriers. Fig. 1g shows an oil field with barriers consisting of a fault and a channel boundary. The determination of the orientation of these barriers should take place to determine the injection pattern.
One of the most controlling reservoir properties is vertical permeability. This property controls upward migration of gas, cross flow or injected fluids, gravity drainage of oil in thick oil columns, and coning of both gas and water.
Vertical permeability can be estimated from core data on a very limited basis. Field measurements by vertical pulse testing require almost perfect mechanical zone isolation and careful management of the perforated completions. By using connectivity mapping between a source and receiver well, vertical permeability can be estimated between layers (Fig. 1h). Connectivity can be determined from a layer in the source well to an adjacent layer in the receiver well.
A pulse test to determine continuity is limited to reservoirs without gas caps, but connectivity mapping can include gas caps (Fig. 1i).
GYPSY PILOT STUDY
The University of Oklahoma's Gypsy pilot site for reservoir characterization near Cleveland, Okla., was originally developed by BP Exploration Inc. with a single five-spot pattern on 330 ft spacing and an observation well.
The variability of the wells is illustrated by the gamma ray logs in Fig. 2.
Well Dallas 5-7 has five identified point bar sands in the core. But 3,467 ft to the east, Dallas 7-7 has six sands, and 325 ft north Dallas 1-7 has three sands. A possible correlation between Wells 5-7 and 7-7 is shown in Fig. 3.
The Gypsy sand is divided into an upper and lower sequence separated over the area by a shale marker.
Fig. 4 is the velocity tomogram from a crosswell seismic survey recorded in Wells 5-7 and 7-7. It shows that the Gypsy sand interval has lower velocity than the shales above and below, but little detail of the thin point bar relationships can be seen.
Fig. 5 shows the processing of the same data using connectivity mapping. Three connections are identified: V Y, and Z. The lowest connection, Z, is characterized as continuous between the top sands in the lower Gypsy interval with no connection to any other sand in the lower unit or to the upper unit.
The upper unit has a thin or discontinuous connection, Y, shown as a weaker measure.
The top-most connection, X, illustrates the connectivity mapping of continuity barriers instead of the reservoir. The shale is continuous between the two wells, indicating that it is the relatively low-velocity interval at that depth.
GEOPHYSICAL CONCEPTS
In the industry, crosswell seismic techniques are being developed for detailed description of oil and gas reservoirs.
The most well-known crosswell technique, velocity tomography, uses mathematics similar to computer tomography (CT) scans used in medicine. These techniques reconstruct the interwell formation velocities from the first and direct travel times.
Another technique, refection mapping, uses techniques similar to vertical seismic profiling. The horizontally traveling energy is separated from the energy moving up and down. The reflected energy is then extracted and migrated with similar methods as used in surface seismic data processing.
Connectivity mapping uses transmission theory to identify and analyze guided wave energy between two well bores and characterizes the formation continuity between wells. The frequency spectra are separated into receiver and source before being correlated to determine the intervals in the two wells that are in the same formation.
Wave guides are layers that have seismic velocity less than the layers above and below. Guided waves are energy internally trapped in the layer. Every wave guide layer is characterized by the dominant frequency and the limits in the high and low frequencies.
Unlike other crosswell seismic imaging methods, crosswell seismic connectivity mapping is extremely robust. it is not adversely affected by velocity anisotropy, dispersion, structural anomalies outside the wave guide, well deviations, or the limited view of the reservoir.
Because connectivity mapping is based on the transmission characteristics of the formations, the results are derived from the relative amplitudes of the received signals and their frequency spectrum. The relative phase of the signal is not considered, simplifying the whole process of data acquisition, processing, and interpretation.
Any suitable downhole seismic source can be used including the drill bit. the whole concept is elegant in its simplicity and reliability. The vertical resolution achieved exceeds any other seismic imaging system available today.
Copyright 1993 Oil & Gas Journal. All Rights Reserved.