SECTION 1
BASIC PROPERTIES AND DATA MANAGEMENT

Naturally occurring rocks are in general permeated with fluid – water, oil, or gas or combinations of these fluids. Oil and gas operators are concerned with the quantities of fluid contained within the rocks and the transmissibility of the fluids through the rocks. The following discussion of fundamental rock properties, fluid saturations and reservoir drive mechanisms will provide background necessary to understand how these properties affect water production in oil and gas wells.

This section also includes a brief discussion on collection and organization of well information and production data. This includes useful plots to assist in analyzing water production and methods to track different costs related to water handling.

Rock Properties.  Porosity  is defined as the ratio of the void space in a rock to the bulk volume of that rock multiplied by 100 to express in percent. It is also referred to as the storage capacity of underground formations. Porosity can be classified according to the mode of origin as 1) original (primary) – developed during deposition of the sediment or 2) induced (secondary) – developed by some geologic process subsequent to the deposition of the rock. Original porosity is typified by the intergranular porosity of sandstones, carbonates, and the interparticle and oolitic porosity of some limestones. Induced porosity is typified by fracture development as found in some shales and limestones or by vugs or solution cavities commonly found in limestones or by dissolution of feldspar in a sandstone. Rocks having original porosity are more uniform in their characteristics than those rocks in which a large part of the porosity is induced. Porosity can be further defined as total or effective. Total porosity is the ratio of the total void space in the rock to the bulk volume of the rock; effective porosity is the ratio of the interconnected void space in the rock to the bulk volume of the rock, each expressed in percent.

Permeability  is a measure of the capacity of the rock medium to transmit or conduct fluids. It is measured in field units of darcys or millidarcys. Flow paths are of varying shapes and sizes and are randomly connected. Fluid flow occurs both horizontally and vertically. Most porous rocks will have spatial variations in permeability. Matrix permeability refers to the flow in primary pore spaces in a rock as opposed to fracture permeability that refers to the flow in cracks or breaks in the rock. In some sand and carbonate reservoirs the formation frequently contains solution channels and natural or artificial fractures. These channels and fractures do not change the permeability of the matrix but do change the effective permeability of the flow network.

Fluid Saturation.  In most oil bearing formations it is believed that the rock was completely saturated with water prior to the invasion and trapping of petroleum.¹ The less dense hydrocarbons migrate to positions of hydrostatic and dynamic equilibrium, thus displacing water from the interstices of the structurally high part of the rock. The oil will not displace all the water. Thus, reservoir rocks normally contain both petroleum hydrocarbons and water (frequently referred to as connate water) occupying the same or adjacent pores. To determine the quantity of hydrocarbons accumulated in a porous rock formation, it is necessary to determine the fluid saturation (oil, water, and gas) of the rock material. The simultaneous existence of two or more fluids in porous rock requires that terms such as capillary pressure, relative permeability, and wettability be defined.

Capillary pressure  is the pressure required to drive a fluid through a pore throat and displace the pore-wetting fluid.  As pore throats become smaller, higher capillary pressures are required to displace the pore-wetting fluid.² Capillary pressure curves are available that provide information regarding pore throat sorting, relative permeabilities, and reservoir quality. The size of the pore throat is related to the residual water saturation. Water cut is related to the capillarity and the distance above the oil-water contact. Capillarity is important to waterflood performance.

Relative permeability  is the ratio of the effective permeability of a particular fluid to a base permeability of the rock. Since it is both a rock property and a fluid property, relative permeability is a difficult concept to understand. The permeability of a rock depends upon the type of fluid that is flowing, characteristics of the rock surface and the pore structure geometry. The presence of more than one fluid at the same time in the pore space of a rock also affects the permeability. Relative permeabilities range from zero to one, and are a function of the fluid saturation.

Wettability.  When two immiscible fluids such as oil and water are together in contact with a rock surface, one of the fluids will preferentially adhere to the rock surface. Wettability refers to a measure of which fluid preferentially adheres to the surface. Most producing reservoirs generally exist in a water-wet state, in which the connate water preferentially adheres to the rock surfaces. If the contact angle from the rock surface through the water is < 90^o, the rock surface is said to be water wet. On the other hand, if the contact angle is > 90^o, the rock is said to be oil wet. Wettability has an influence on the interstitial water saturation, residual oil saturation, capillary pressure, relative permeability, and waterflood performance.

Reservoir Drive Mechanisms.  Several sources of energy exist in the formation. In the case of liquid petroleum, the natural energy is the expansive energy of the liquid petroleum and the gas dissolved in the liquid petroleum at the elevated pressure at which the petroleum is confined. In addition to the expansive energy of the petroleum hydrocarbons, all petroleum accumulations are associated with water. The oil accumulation may be surrounded by water-bearing formations. This water is subjected to elevated pressures in the subsurface. Upon withdrawal of the fluid from the petroleum reservoir, the reservoir becomes a pressure sink; the contiguous water flows into the petroleum reservoir, displacing oil or gas toward the wellbores. In addition to expansive energies, there is also the force of gravity acting at all times to promote segregation of the various fluids. Gas tends to occupy the higher places in the accumulation; oil, being denser than gas and less dense than water, tends to occupy the intermediate position; and water tends to underlie the petroleum. Frequently, oil fields are found in which a part of the reservoir is liquid saturated and a part is gas saturated. This type of accumulation is referred to as an oil reservoir with a gas cap.

Solution-gas or depletion drive  is a petroleum reservoir with no original free gas cap and no associated active water; the principal energy is the expansion and dissociation of gas in solution in the oil. Water production is generally minimal. The solution-gas drive is characterized by a rapid pressure decline and low recovery efficiency.

Solution-gas-gas-cap drive  is a petroleum reservoir containing an original free gas cap with no associated active water. Reservoir pressure is maintained at higher levels in most instances (if the gas cap is not prematurely depleted), thus improving recovery efficiency. The degree of improvement depends on the size of the gas cap relative to the oil zone and on the production procedure used. As with solution-gas drive, water production is generally minimal.

Water drive  is a petroleum reservoir associated with water-bearing formations that are so active that little or no pressure drop occurs when hydrocarbon fluids are withdrawn. Water drive is the most efficient in maintaining reservoir pressure and usually yields the highest recovery efficiency. Water production varies significantly depending on structural position and nature of the water drive.

Collecting and Organizing Well and/or Production Data.  Wells are basically the source of all information concerning the reservoir. Formation evaluation data must be obtained during particular phases of the drilling and completion of a well, since certain types of data are not obtainable later. Reservoir fluid and production data are typically obtained after the wells are completed; consequently the operator has more latitude in taking such data.

Wellbore schematics  are an excellent way of concisely capturing and displaying well data. When relevant well and reservoir data are properly analyzed, the results can help to explain both production performance and reservoir performance. The importance of keeping good individual well records of all production and injection data as well as workover information cannot be over-emphasized. It is not enough to know production rate for the entire lease or field. A test on each production well at least once or twice a month is generally sufficient to identify individual well rates.

Graphical plots  of data are visual displays that assist the operator in defining specific occurrences during the life of a well. Plots provide insight to individual well and overall project performance. Interaction between wells can also be observed. The plots can be done by hand, with common spreadsheet software, or using specific oil and gas software. A major advantage of using the computer for data storage is the speed with which data can be updated and displayed graphically. The operator can quickly and easily access the same data to prepare plots for an entire project, individual wells, groups of wells, patterns, or other study areas.

Oil production versus time.  Plots of oil production will help the operator observe and better understand occurrences during the life of a well. A semi-log plot of oil production versus time is commonly referred to as a decline curve. Logarithm of oil production rate is the ordinate (or y axis) and time, using a linear scale, is the abscissa (or x axis). This type of plot reveals changes in oil production and is used to determine information such as 1) the time at which production rate will reach its economic limit by extrapolating production decline trends, 2) the time at which oil rate reaches a peak, and 3) the time of initial production response from water injection.

Rates versus time.  Plots of various rates versus time can assist in determining specific occurrences associated with a producing well. These rates include water production, water-oil ratios (watercut), gas-oil ratios, water injection rates, and cumulative water injection. It is common to plot different rates versus time on the same graph. Such comparisons can assist in determining a relationship between different variables, such as injection and production rates in a waterflood. Fluctuations in one rate can have an effect on another.

Water-oil ratio (WOR) versus cumulative oil production.  A semi-log plot of WOR versus cumulative oil production is also informative in recognizing occurrences during the life of a well. Logarithm of WOR is the ordinate and linear cumulative oil production is the abscissa. This type of plot reveals changes in water production as a function of oil production. Economic limits can be shown easily and because the area under the curve represents total water production, everything necessary to track a well is clearly shown. Sharp increases in WOR can indicate a problem, such as a casing leak or water breakthrough in a water-drive reservoir or waterflood. High WOR associated with low cumulative oil production can indicate a channeling problem. This type of plot should be done for the project and for individual wells. When properly constructed, these plots are also useful in predicting the ultimate recovery at a known WOR. If increased WOR occurs early in the life of a well or is associated with low cumulative oil production, a review of individual well data, geological description, and engineering data is warranted to define appropriate remedial work, such as permeability modification using gelled polymers. Successful remediation can result in a reversal of the WOR curve, followed by a flattening of the curve. This type of work can reduce lifting costs by decreasing the amount of water production, increasing the sweep efficiency and extending the economic life of the project or well.

Hall plots  are most often used to analyze injection wells, but they can also be used to analyze fluid injection treatments in producing wells. They provide information on fill-up, skin damage, formation fracturing, and water channeling. Required data are cumulative injection volume and injection pressure. The summation of the surface or bottomhole pressure multiplied by time is plotted versus the cumulative fluid injected on coordinate paper. Changes in the slope of the plotted line indicate a change in resistivity associated with fluid injection in the reservoir.

Knowing Your Water-related Costs.  Water production can make or break a project’s performance by reducing the flow rate or ultimate recovery or by raising costs. The cost of lifting, separating, handling and disposing of this water is substantial. In addition to the economic burden, water can also directly reduce hydrocarbon production. Water plays a role throughout the entire life cycle of a well. A listing of direct costs and impact areas is given in Table 1.³

Table 1. Water-related Cost and Impact Areas

  Rudolph, J. and Miller, J., “Downhole Produced Water Disposal Improves Gas Rate,” GRI October 2001 publication.

Many companies don’t recognize or account for the full cost of water management since accounting is often spread over many corporate departments. Consequently, the impact of water is underestimated and opportunities to implement strategies and improve inefficiencies are overlooked. Ironically, smaller companies (independent producers) are in a better position to recognize the cross-functional costs and implications, but they tend to lack the resources to identify and implement effective water management strategies. These costs and impacts impose an enormous burden on the industry’s ultimate return on investment and reduce economically recoverable reserves. In many cases a modest gain in economic efficiencies can lead to a substantially large economic benefit.