Table Of Content

1 1 Defining Enhanced Oil Recovery Enhanced oil recovery (EOR) is oil recovery by the injection of materials not normally present in the reservoir. This definition covers all modes of oil recovery processes (drive, push-pull, and well treatments) and most oil recovery agents. Enhanced oil recovery technologies are also being used for in-situ extraction of organic pollutants from permeable media. In these applications, the extraction is referred to as cleanup or remediation, and the hydrocarbon as product. Various sections of this text will discuss remediation technologies specifically, although we will mainly discuss petroleum reservoirs. The text will also describe the application of EOR technology to carbon dioxide storage where appropriate. The definition does not restrict EOR to a particular phase (primary, secondary, or tertiary) in the producing life of a reservoir. Primary recovery is oil recovery by natural drive mechanisms: solution gas, water influx, and gas cap drives, or gravity drainage. Figure 1-1 illustrates. Secondary recovery refers to techniques, such as gas or water injection, whose purpose is mainly to raise or maintain reservoir pressure. Tertiary recovery is any technique applied after secondary recovery. Nearly all EOR processes have been at least field tested as secondary displacements. Many thermal methods are commercial in both primary and secondary modes. Much interest has been focused on tertiary EOR, but the definition given here is not so restricted. The definition does exclude waterflooding but is intended to exclude all pressure maintenance processes. The distinction between pressure maintenance 2 and displacement is not clear, since some displacement occurs in all pressure maintenance processes. Moreover, agents such as methane in a high-pressure gas drive, or carbon dioxide in a reservoir with substantial native CO , do not satisfy the 2 definition, yet both are clearly EOR processes. The same can be said of CO storage. 2 Usually the EOR cases that fall outside the definition are clearly classified by the intent of the process. In the last decade, improved oil recovery (IOR) has been used interchangeably with EOR or even in place of it. Although there is no formal definition, IOR typically refers to any process or practice that improves oil recovery (Stosur et al., 2003). IOR therefore includes EOR processes but can also include other practices such as waterflooding, pressure maintenance, infill drilling, and horizontal wells. PPPrrriiimmmaaarrryyy RRReeecccooovvveeerrryyy AAArrrtttiiifffiiiccciiiaaalll LLLiiifffttt NNNaaatttuuurrraaalll FFFlllooowww PPPuuummmppp --- GGGaaasss LLLiiifffttt CCoonnvveennttiioonnaall RReeccoovveerryy SSSeeecccooonnndddaaarrryyy RRReeecccooovvveeerrryyy PPPrrreeessssssuuurrreee MMMaaaiiinnnttteeennnaaannnccceee WWWaaattteeerrrffflllooooooddd WWWaaattteeerrr///GGGaaasss RRReeeiiinnnjjjeeeccctttiiiooonnn TTTeeerrrtttiiiaaarrryyy RRReeecccooovvveeerrryyy EEnnhhaanncceedd TTThhheeerrrmmmaaalll CCChhheeemmmiiicccaaalll RReeccoovveerryy SSSooolllvvveeennnttt OOOttthhheeerrr Figure 1-1. Oil recovery classifications (adapted from the Oil and Gas Journal biennial surveys). 1-1 EOR INTRODUCTION The EOR Target We are interested in EOR because of the amount of oil to which it is potentially applicable. This EOR target oil is the amount unrecoverable by conventional means (Fig. 1-1). A large body of statistics shows that conventional ultimate oil recovery (the percentage of the original oil in place at the time for which further conventional 3 recovery becomes uneconomic) is about 35%. This means for example that a field that originally contained 1 billion barrels will leave behind 650,000 barrels at the end of its conventional life. Considering all of the reservoirs in the U.S., this value is much larger than targets from exploration or increased drilling. The ultimate recovery is shown in Fig. 1-2. This figure also shows that there is enormous variability in ultimate recovery within a geographic region, which is why we cannot target reservoirs with EOR by region. Reservoirs that have an exceptionally large conventional recovery are not good tertiary EOR candidates. Figure 1-2 shows also that the median ultimate recovery is the same for most regions, a fact no doubt bolstered by the large variability within each region. 100 80 % y, c n e fici 60 Ef y er v o c e R 40 e at m Ulti 20 0 Middle East CIS LatAm Africa Far East Europe Austral Asia US Figure 1-2. Box plots of ultimate oil recovery efficiency. 75% of the ultimate recoveries in a region fall within the vertical boxes; the median recovery is the horizontal line in the box; the vertical lines give the range. Ultimate recovery is highly variable, but the median is about the same everywhere (from Laherre, 2001). 1-2 THE NEED FOR EOR Enhanced oil recovery is one of the technologies needed to maintain reserves. Reserves 4 Reserves are petroleum (crude and condensate) recoverable from known reservoirs under prevailing economics and technology. They are given by the following material balance equation: ⎛Production⎞ ⎛Present⎞ ⎛ Past ⎞ ⎛ Additions⎞ ⎜ ⎟ ⎜ ⎟=⎜ ⎟+⎜ ⎟−⎜ from ⎟ ⎝reserves⎠ ⎝reserves⎠ ⎝to reserves⎠ ⎜ ⎟ ⎝ reserves ⎠ There are actually several categories of reservoirs (proven, etc.) which distinctions are very important to economic evaluation (Rose, 2001; Cronquist, 2001). Clearly, reserves can change with time because the last two terms on the right do change with time. It is in the best interests of producers to maintain reserves constant with time, or even to have them increase. Adding to Reserves The four categories of adding to reserves are 1. Discovering new fields 2. Discovering new reservoirs 3. Extending reservoirs in known fields 4. Redefining reserves because of changes in economics of extraction technology We discuss category 4 in the remainder of this text. Here we substantiate its importance by briefly discussing categories 1 to 3. Reserves in categories 1 to 3 are added through drilling, historically the most important way to add reserves. Given the 2% annual increase in world-wide consumption and the already large consumption rate, it has become evident that reserves can be maintained constant only by discovering large reservoirs. But the discovery rate of large fields is declining. More importantly, the discovery rate no longer depends strongly on the drilling rate. Equally important, drilling requires a substantial capital investment even after a field is discovered. By contrast, the majority of the capital investment for EOR has already been made (if previous wells can be used). The location of the target field is known (no need to explore), and targets tend to be close to existing markets. Enhanced oil recovery is actually a competitor with conventional oil recovery because most producers have assets or access to assets in all of the Fig. 1-1 categories. The competition then is joined largely on the basis of economics in addition to reserve replacement. At the present, many EOR technologies are competitive with drilling-based reserve additions. The key to economic competitiveness is how much oil can be recovered with EOR, a topic to which we next turn. 5 1-3 INCREMENTAL OIL Defintion A universal technical measure of the success of an EOR project is the amount of incremental oil recovered. Figure 1-3 defines incremental oil. Imagine a field, reservoir, or well whose oil rate is declining as from A to B. At B, an EOR project is initiated and, if successful, the rate should show a deviation from the projected decline at some time after B. Incremental oil is the difference between what was actually recovered, B to D, and what would have been recovered had the process not been initiated, B to C. Since areas under rate-time curves are amounts, this is the shaded region in Fig. 1-3. Figure 1-3. Incremental oil recovery from typical EOR response (from Prats, 1982) 6 As simple as the concept in Fig. 1-3 is, EOR is difficult to determine in practice. There are several reasons for this. 1. Combined (comingled) production from EOR and nonEOR wells. Such production makes it difficult to allocate the EOR-produced oil to the EOR project. Comingling occurs when, as is usually the case, the EOR project is phased into a field undergoing other types of recovery. 2. Oil from other sources. Usually the EOR project has experienced substantial well cleanup or other improvements before startup. The oil produced as a result of such treatment is not easily differentiated from the EOR oil. 3. Inaccurate estimate of hypothetical decline. The curve from B to C in Fig. 1- 3 must be accurately estimated. But since it did not occur, there is no way of assessing this accuracy. Ways to infer incremental oil recovery from production data range from highly sophisticated numerical models to graphical procedures. One of the latter, based on decine curve analysis, is covered in the next section. Estimating Incremental Oil Recovery Through Decline Curves Decline curve analysis can be applied to virtually any hydrocarbon production operation. The following is an abstraction of the practice as it applies to EOR. See Walsh and Lake (2003) for more discussion. The objective is to derive relations between oil rate and time, and then between cumulative production and rate. The oil rate q changes with time t in a manner that defines a decline rate D according to 1 dq =−D 1.3-1 q dt The rate has units of (or [=]) amount or volume per time and D [=]1/time. Time is in units of days, months, or even years consistent with the units of q. D itself can be a function of rate, but we take it to be constant. Integrating Eq. 1.3-1 gives q=qe−Dt 1.3-2 i where q is the initial rate or q evaluated at t = 0. Equation 1.3-2 suggests a i semilogarithmic relationship between rate and time as illustrated in Fig. 1-3. Exponential decline is the most common type of analysis employed. 7 llloooggg (((qqq))) qqq iii -----DDDDD SSSSllllooooppppeeee ==== 22222.....333330000033333 DDDeeecccllliiinnneee pppeeerrriiioooddd bbbeeegggiiinnnsss qqq LLLiiifffeee EEELLL ttt 000 Figure 1-3. Schematic of exponential decline on a rate-time plot. Figure 1-3 schematically illustrates a set of data (points) which begin an exponential decline at the ninth point where, by definition t = 0. The solid line represents the fit of the decline curve model to the data points. q is the rate given by i the model at t=0, not necessarily the measured rate at this point. The slope of the model is the negative of the decline rate divided by 2.303, since standard semilog graphs are plots of base 10 rather than natural logarithms. Because the model is a straight line, it can be extrapolated to some future rate. If we let q designate the economically limiting rate (simply the economic EL limit) of the project under consideration, then where the model extrapolation attains q is an estimate of the project’s (of well’s, etc.) economic life. The economic limit EL is a nominal measure of the rate at which the revenues become equal to operating expenses plus overhead. q can vary from a fraction to a few hundred barrels per EL day depending on the operating conditions. It is also a function of the prevailing economics: as oil price increases, q decreases, an important factor in reserve EL considerations. The rate-time analysis is useful, but the rate-cumulative curve is more helpful. The cumulative oil produced is given by ξ=t N = ∫ qdξ . p ξ=0 8 The definition in this equation is general and will be employed throughout the text, but especially in Chap. 2. To derive a rate -cumulative expression, insert Eq. 1.3-1, integrate, and identify the resulting terms with (again) Eq. 1.3-1. This gives q=q −DN 1.3-3 i p Equation 1.3-3 says that a plot of oil rate versus cumulative production should be a straight line on linear coordinates. Figure 1-4 illustrates. qqq qqq iii SSSlllooopppeee === ---DDD MMMooobbbiiillleee oooiiilll qqq EEELLL RRReeecccooovvveeerrraaabbbllleee oooiiilll NNN 000 ppp Figure 1-4. Schematic of exponential decline on a rate-cumulative plot. You should note that the cumulative oil points being plotted on the horizontal axis of this figure are from the oil rate data, not the decline curve. It this were not so, there would be no additional information in the rate-cumulative plot. Calculating N p normally requires a numerical integration with something like the trapezoid rule. Using model Eqs 1.3-2 and 1.3-3 to interpret a set of data as illustrated in Figs. 1-3 and 1-4 is the essence of reservoir engineering practice, namely 1. Develop a model as we have done to arrive at Eqs. 1.3-2 and 1.3-3. Often the model equations are far more complicated than these, but the method is the same regardless of the model. 2. Fit the model to the data. Remember that the points in Figs. 1-3 and 1-4 are data. The lines are the model. 3. With the model fit to the data (the model is now calibrated), extrapolate the model to make predictions. 9 At the onset of the decline period, the data again start to follow a straight line through which can be fit a linear model. In effect, what has occurred with this plot is that we have replaced time on Fig. 1-3 with cumulative oil produced on Fig. 1-4, but there is one very important distinction: both axes in Fig. 1-4 are now linear. This has three important consequences. 1. The slope of the model is now –D since no correction for log scales is required. 2. The origin of the model can be shifted in either direction by simple additions. 3. The rate can now be extrapolated to zero. Point 2 simply means that we can plot the cumulative oil produced for all periods prior to the decline curve period (or for previous decline curve periods) on the same rate-cumulative plot. Point 3 means that we can extrapolate the model to find the total mobile oil (when the rate is zero) rather than just the recoverable oil (when the rate is at the economic limit). Rate-cumulative plots are simple yet informative tools for interpreting EOR processes because they allow estimates of incremental oil recovery (IOR) by distinguishing between recoverable and mobile oil. We illustrate how this comes about through some idealized cases. Figure 1-5 shows a rate-cumulative plot for a project having an exponential decline just prior to and immediately after the initiation of an EOR process. qqq qqq EEELLL IIIOOORRR NNN IIIInnnnccccrrrreeeemmmmeeeennnnttttaaaallll ppp PPPrrrooojjjeeecccttt bbbeeegggiiinnnsss mmmmoooobbbbiiiilllleeee ooooiiiillll 10 Figure 1-5. Schematic of exponential decline curve behavior on a rate-cumulative plot. The EOR project produces both incremental oil (IOR), and increases the mobile oil. The pre- and post-EOR decline rates are the same. We have replaced the data points with the models only for ease of presentation. Placing both periods on the same horizontal axis is permissible because of the scaling arguments mentioned above. In this case, the EOR process did not accelerate the production because the decline rates in both periods are the same; however, the process did increase the amount of mobile oil, which in turn caused some incremental oil production. In this case, the incremental recovery and mobile oil are the same. Such idealized behavior would be characteristic of thermal, micellar-polymer, and solvent processes. qqq IIIOOORRR qqq EEELLL NNN ppp PPPrrrooojjjeeecccttt bbbeeegggiiinnnsss Figure 1-6. Schematic of exponential decline curve behavior on a rate-cumulative plot. The EOR project produces incremental oil at the indicated economic limit but does not increase the mobile oil. Figure 1-6 shows another extreme where production is only accelerated, the pre- and post-EOR decline rates being different. Now the curves extrapolate to a common mobile oil but with still a nonzero IOR. We expect correctly that processes that behave as this will produce less oil than ones that increase mobile oil, but they can still be profitable, particularly, if the agent used to bring about this result is inexpensive. Processes that ideally behave in this manner are polymer floods and polymer gel processes, which do not affect residual oil saturation. Acceleration processes are especially sensitive to the economic limit; large economic limits imply large IOR.