WO2015074717A1

WO2015074717A1 - Measurement of heavy hydrocarbon production rate

Info

Publication number: WO2015074717A1
Application number: PCT/EP2013/074503
Authority: WO
Inventors: Ivar Øystein LARSEN; Morten Tande
Original assignee: Statoil Petroleum ASA
Current assignee: Equinor Energy AS
Priority date: 2013-11-22
Filing date: 2013-11-22
Publication date: 2015-05-28
Anticipated expiration: 2016-05-22

Abstract

The present invention provides a method for measuring the production rate of heavy hydrocarbons from a reservoir, the reservoir being connected to a production line that enables said heavy hydrocarbons to be recovered, the method comprising: the addition of a diluent at a constant flow rate to the heavy hydrocarbons in the production line downstream from the reservoir; the provision of sufficient time for the diluent and the heavy hydrocarbons to mix homogeneously; and the determination of the production rate of the heavy hydrocarbons from the reservoir by measuring the viscosity of a sample of the homogeneous mixture thus obtained, said sample being taken from a second point on the production line downstream from the point of addition of the diluent; as well as uses of a viscosity calibration curve for reservoirs for determining production rate etc. and systems for measuring production rate from a reservoir.

Description

Measurement of Heavy Hydrocarbon Production Rate Field of the Invention

The present invention relates to a method for measuring the production rate of heavy hydrocarbons from a reservoir based on the addition of a diluent to the heavy hydrocarbons in a production line at a constant flow rate and determining the production rate from measuring the viscosity of the mixture thus obtained. It also relates to systems for measuring the production rate of heavy hydrocarbons from a reservoir and the use of a calibration curve to measure the production rate.

Background to the Invention

Heavy hydrocarbons, e.g. bitumen, oil which contains large quantities of long chain hydrocarbons, paraffins, waxes, aromatics (including polyaromatic hydrocarbons) terponoids, asphaltenes, oil sand or shale reservoirs etc. represent a huge natural source of the world's total potential reserves of oil and specialist methods have been developed for recovering such hydrocarbons. Present estimates place the quantity of heavy hydrocarbon reserves at several trillion barrels, more than five times the known amount of the conventional, i.e. non-heavy, hydrocarbon reserves. This is partly because heavy hydrocarbons are generally difficult to recover by conventional recovery processes and thus have not been exploited to the same extent as non- heavy hydrocarbons. Heavy hydrocarbons possess very high viscosities and low API (American Petroleum Institute) gravities which makes them difficult, if not impossible, to pump in their native state. Additionally heavy hydrocarbons are characterised by high levels of unwanted compounds such as asphaltenes, trace metals and sulphur that need to be processed appropriately during recovery and/or refining.

Some methods have been developed to extract and process heavy hydrocarbon mixtures. The method that is used onshore most often commercially today for heavy hydrocarbon recovery from reservoirs is steam assisted gravity drainage (SAGD). In this method two horizontal wells are drilled a sort distance apart (e.g. approximately five meters apart) then steam is injected into the reservoir through an upper wellbore permeating the oil sand. Steam softens the heavy hydrocarbon (e.g. bitumen) and enables it to flow out of the reservoir and into the lower well. From there it is pumped to the surface facilities. A recent development has been the injection of about 10% solvents (sometimes called diluents) with the steam. The idea of this improvement is that the diluent condenses and mixes into the hydrocarbon in the formation and thereby decreases its viscosity and increases its API gravity and thus enhances its recovery.

In other heavy oil fields, both onshore and offshore there are reservoirs where the oil is naturally flowing, but the wellstream have to be pumped to the surface by an electric or hydraulic driven downhole pump. In some cases the artificial lift is aided by solvent added directly to the well to reduce the oil viscosity and thus improve the flow and transport properties. Oil production rate allocations for a field are of great importance. For example, it is often a governmental requirement to be able to measure oil production rates, and often from each individual well. The information is also of interest to the shareholders of a field. Heavy hydrocarbons tend to be of very high viscosity, or be present in reservoirs which otherwise flow so poorly, that measurement of heavy hydrocarbon production rates in such reservoirs is generally challenging.

The oil industry reconciles fiscally measured hydrocarbon production with estimated production from associated wells. This process, known as allocation, is important for several reasons including accounting for field production to owners and

governments, field surveillance, and volumetric input to reservoir simulators.

Traditionally companies perform allocation monthly, reconciling the less accurate sum of the well tests adjusted by well uptimes with the more accurate fiscal measurements. This process has several inherent inaccuracies including less-than- perfect well tests, lack of precisely knowing when wells were off production, unknown well flow changes, and the methods for allocating the difference between fiscal and well test measurements.

Ineffective allocation can lead to financial consequences because of inaccuracies in volumes allocated between multiple owners and various tax regimes.

Inaccuracies can also feed through to reservoir simulators that assist in decision making such as where to drill the next well. These inaccuracies often compound with time, as monthly allocation occurs during the field's life cycle.

A number of methods currently exist for measuring heavy hydrocarbon production rates, but none of them are satisfactory. One is the conducting of measurements after routing the well to a test separator. A second known method is the use of indirect methods based on pressure drop calculations. A third known method involves the incorporation of multiphase flow meters mounted into the production line. A fourth known method involves the calibration of flow rates based on RPM on a downhole pump (ESP). The final method currently known in the art for the measuring of the heavy hydrocarbon production rate is by determining the pressure balance over a venturi valve or a choke valve something which is currently only in research and development phase.

Unfortunately, these existing methods for production rate allocations for heavy hydrocarbon are expensive, time consuming and unreliable. Not all oil fields have test separators, which makes measuring the production rates of individual wells in a field difficult. Furthermore, multiphase meters cost $100,000 - $500,000 per well, and their use for viscous oils is not well documented. Additionally, measurements based on RPM on downhole pumps (ESP) are uncertain and complicated, and require a significant amount of knowledge about both pump performance and water cut.

A need therefore exists for a means of determining production rates of heavy hydrocarbons from reservoirs in a field which is cheaper, easier to implement and more reliable than these existing methods for determining rate allocations.

Statement of the Invention

It has now surprisingly been discovered that injecting a diluent at an accurate, controlled flow rate into heavy hydrocarbons recovered from a reservoir of interest, and accurately measuring the viscosity of a sample of a mixture of the heavy hydrocarbons and this diluent downstream from the injection point, can be used to calculate the production rate of the heavy hydrocarbon from a heavy hydrocarbon producing reservoir easily, efficiently and cheaply, thus providing a solution to the problem addressed by the present invention.

Thus, in a first aspect of the present invention there is provided a method for measuring the production rate of heavy hydrocarbons from a reservoir, wherein said reservoir having said heavy hydrocarbons therein is connected to a production line that enables said heavy hydrocarbons to be recovered, said method comprising the following steps:

(i) the addition of a diluent at a constant flow rate to said heavy hydrocarbons in said production line downstream from said reservoir; (ii) the provision of sufficient time for said diluent and said heavy hydrocarbons from said reservoir to mix homogeneously; and

(iii) the determination of the production rate of said heavy hydrocarbons produced from said reservoir by measuring the viscosity of a sample of the homogeneous mixture obtained in step (ii), said sample being taken from a second point on the production line downstream from the point of addition of said diluent.

This new method requires a minimum of equipment and investment for retrofit installation, and has the further advantage of being very simple to implement at greenfield installations. Furthermore, by using advances in online viscometer development, it is possible to apply this new method to online measurements of viscosity and, hence, determine oil production rates online.

In a second aspect of the present invention there is provided use of a viscosity calibration curve of homogeneous mixtures of heavy hydrocarbons recovered from a reservoir by means of a production line and a diluent added at different

concentrations to said production line at a constant flow rate to determine:

(i) the viscosity of homogeneous mixtures of heavy hydrocarbons recovered from said reservoir by means of said production line and a diluent, added at different concentrations, at a constant flow rate to said heavy hydrocarbons in the production line downstream from said reservoir;

(ii) the concentration of said diluent in the homogeneous mixture of heavy hydrocarbons and diluent obtained by addition of said diluent; and

(iii) the diluent fraction of said diluent in said homogeneous mixture of heavy hydrocarbons and diluent.

By making a plot of the viscosity of homogeneous mixtures of heavy hydrocarbons from a reservoir of interest and diluent added at different concentrations against the concentration of said diluent as a percentage by volume in said homogeneous mixtures at a fixed temperature and pressure, it is possible to establish a standard viscosity calibration curve for a heavy hydrocarbon reservoir of interest. From this, it is possible to determine integers (i), (ii) and (iii) above and from these together with a knowledge of the flow rate of addition of the diluent, it is possible to determine the production flow rate of the heavy hydrocarbons for the reservoir of interest. Thus, in a third aspect of the present invention there is provided use of a viscosity calibration curve for a heavy hydrocarbon reservoir for measuring the production rate of heavy hydrocarbons from a reservoir.

In a fourth aspect of the present invention there is provided a system for measuring the production rate of heavy hydrocarbons from a reservoir, said system comprising:

(i) a production pipeline that is connected to said reservoir and which is provided with means such that it is able to recover said heavy hydrocarbons from said reservoir;

(ii) a means for adding a diluent to said heavy hydrocarbons in said production line downstream from said reservoir; and

(iii) a means for removing a sample of a homogeneous mixture of said heavy hydrocarbons and said diluent from said hydrocarbon production line formed after the addition of said diluent, wherein said means is downstream from the point of addition of said diluent by said means (ii).

Detailed Description of the Invention

As explained above, the method, uses and system of the present invention provide a simple, cheap alternative to those approaches that have been used previously to allocate production rates to reservoirs. They require a minimum of equipment and investment for retrofit installation, and have the further advantage of being simple to implement at greenfield installations.

The viscosity of different reservoirs on an oil field can often be very different.

However, for an individual reservoir a single, stable viscosity is expected over the lifetime of a field. We have found that adding a diluent to a viscous heavy hydrocarbon, even in concentrations as low as 0.1 - 2% reduces the viscosity significantly (particularly at low temperatures). Preferably, the viscosity of the diluent is lower than the viscosity of the heavy hydrocarbons obtained from the reservoir, and contain minium amounts of light fractions that can be flashed off during sampling and sample preparation. Preferably, the viscosity of said diluent is from 0.1 to 7500 mPa.s, more preferably from 0.1 to 100 mPa.s and most preferably fromO.1 to 10 mPa.s at 37°C.

The present invention is concerned with the measurement of the production rate of heavy hydrocarbons from a reservoir, typically a subterranean reservoir. As used herein, the term "heavy hydrocarbons" is used to refer to a combination of different hydrocarbons, i.e. to a combination of various types of molecules that contain carbon atoms and, in many cases, attached hydrogen atoms, a "hydrocarbon mixture". A "hydrocarbon mixture" may comprise a large number of different molecules having a wide range of molecular weights. Generally at least 90% by weight of the

"hydrocarbon mixture" consists of carbon and hydrogen atoms. Up to 10% by weight may be present as sulfur, nitrogen and oxygen as well as metals such as iron, nickel and vanadium (i.e. as measured sulfur, nitrogen, oxygen or metals). These are generally present in the form of impurities of the desired "hydrocarbon mixture".

A heavy hydrocarbon mixture in accordance with the present invention comprises a greater proportion of hydrocarbons having a higher molecular weight than a relatively lighter hydrocarbon mixture. As used herein a heavy hydrocarbon mixture preferably has an API gravity of from about 5 to about 20, more preferably an API of 1 1 to 19. Examples of heavy hydrocarbon mixtures that typically have API gravities falling in these ranges are bitumens, tars, oil shales , oil sand deposits and offshore heavy oil "Heavy hydrocarbons" and "heavy hydrocarbon mixtures" as defined and explained above are thus, for the purposes of this invention, synonymous.

The amount of diluent that is added will vary considerably depending upon factors such as temperature (see below), pressure, and viscosity of both the diluent and the heavy hydrocarbons. Typically, the amount of external diluent added to said heavy hydrocarbons in said production line is from 0.1 - 50 % by volume of the resulting mixture and preferably 5-20% by volume, e.g. 5%, 8%, 10%, 15% or 20%.

As noted earlier, the diluent is added at a constant flow rate to the heavy

hydrocarbons in the production line downstream from the reservoir. In one preferred embodiment, the addition of said diluent to the heavy hydrocarbons in the production line is upstream of a downhole pump. Alternatively, the diluent can be added to the heavy hydrocarbons in said production line is upstream of a gas lift valve. In another alternative, the addition of said diluent to said heavy hydrocarbons in said production line is upstream at a transport distance to allow sufficient mixing intensity to make a homogenous fluid of the diluent/crude oil mixture.

This new method is generally applicable to the use of any oil soluble chemical as the diluent. The diluent will be chosen following considerations such as stability of the resulting mixture, the price of the diluent and health and safety considerations. An appropriate choice of diluent would be one which is normally readily available at an oil production facility. Generally, suitable diluents comprise C₄-₃o hydrocarbons. A non-limiting list of examples of suitable diluents for use includes naphtha, light crude oil, diesel, natural-gas condensate, synthetic crude and mixtures thereof, and particularly preferred diluents are selected from diesel and natural-gas condensate or a mixture thereof.

Ideally, the diluent should be added at an accurate flow rate, so a suitably accurate and stable pump should be used. The diluent is added to the heavy hydrocarbons in the production line by means of a pump that is able to deliver the desired flow rate used in combination with a calibrated flowmeter. Optionally, this can be used in combination with a control system. For relatively small flows, less than 150 m³/h the diluent is added by means of a displacement pump used in combination with a calibrated flowmeter.

It has been found that the comparative viscosity differences of the resulting homogeneous mixture of heavy hydrocarbons from the reservoir and the diluent between heavy hydrocarbons diluted at varying concentrations of diluent is higher at lower temperature. Thus, at lower temperature the resolution will be higher and the accuracy better. Typically, the method of measuring the production rate of heavy hydrocarbons from a reservoir according to the present invention is conducted at a temperature of from 0°C to 250°C, preferably from 30°C to 90°C, and most preferably from 0°C to 20°C or 20°C to 40°C.

In general, the viscosity of the wells on a field can be different. However, for a single heavy hydrocarbon reservoir a stable viscosity is expected over a field lifetime. As a consequence it is relatively easy to make a calibration curve for viscosity as a function of diluent addition, and to exploit this to determine heavy hydrocarbon production rate.

The production rate of heavy hydrocarbons from a reservoir of interest may be calculated according to the following equation: rrihydrocarbons = m_dil (1/c - 1 ), wherein m hy rocarbons is the production rate of heavy hydrocarbons to be determined, m_dil is the flow rate of addition of the diluent to the heavy hydrocarbons in step (ii) of the method according to the first aspect of the present invention, and c is the diluent fraction.

The diluent fraction c can be determined by the following steps: (i) the measurement at a fixed temperature and pressure of the viscosity of the sample of the homogeneous mixture obtained in step (ii) of the method according to the first aspect of the invention at the second point on the production line

downstream from the point of addition of said diluent in step (iii) of said method;

(ii) comparison of the viscosity measured in step (i) to a calibration curve of the viscosity of homogeneous mixtures of heavy hydrocarbons from said reservoir at various dilutions of diluent against the concentration of diluent as a percentage by volume in said homogeneous mixtures of said heavy hydrocarbons from said reservoir and said diluents, to give the concentration of the diluent in the

homogeneous mixture, wherein the calibration curve is prepared at a fixed temperature and pressure that is the same as that adopted in the viscosity measurement in step (i); and

(iii) conversion of said concentration to a fraction to give the desired diluent fraction c.

Typically, when taking samples from a water continuous flow, it is difficult to determine the correct water cut inside the tube, so the sample will be an arbitrary mix of heavy hydrocarbons, diluent and water.

Gas and bulk water is always separated first from the sample. In a preferred embodiment of the first aspect of the present invention, dispersed water in the heavy hydrocarbon phase is removed from the sample before determining the viscosity of the sample of the homogeneous mixture of heavy hydrocarbons and diluent obtained in step (ii) of the first aspect of the invention. This can be achieved by, for example, centrifuging the sample at a temperature of from 70 to 100°C, preferably 90°C (which is the chosen sample preparation temperature). Other methods, like bench-size electrostatic coalsecence (in which electrical fields are used to induce droplet coalescence in water-in-crude-oil emulsions to increase the droplet size) can also be used to remove the dispersed water.

The remaining water concentration in the sample of the homogeneous mixture that is removed in step (iii) of the first aspect of the present invention is analyzed and determined, e.g. by Karl-Fisher titration.

The viscosity of the remaining sample of the homogeneous mixture of heavy hydrocarbons from the reservoir of interest and diluent is then measured at a low and controlled temperature (e.g. 0 to 30°C, more preferably 20°C) using a commercial viscometer. The viscometer could, for example, be a rotational or oscillatory viscometer (e.g. an Anton Paar viscometer) with a thermoelectric temperature controlled measure chamber (e.g. a Peltier temperature controlled measure chamber) and a measure bob suited for viscous oils.

If the water content in the sample as determined by, for example, Karl-Fischer titration is significant, e.g. over 0.5% , the viscosity measurement of the sample of the homogeneous mixture removed in step (iii) of the first aspect of the present invention is corrected for said water content. This correction for water content of the viscosity of the sample of the homogeneous mixture of the heavy hydrocarbons and diluent can be determined using, for example, the Einstein or Brinkman equation.

It can be seen from above that viscosity calibration curves for reservoirs of interest can be used to determine various parameters. In particular, they can be used to determine:

(i) the viscosity of a mixture of heavy hydrocarbons recovered from said reservoir by means of a production line and a diluent added at a constant flow rate downstream from said reservoir to said heavy hydrocarbons in the production line;

Furthermore, as explained above, from the diluent fraction c determined from the viscosity calibration curve it is possible to determine the production rate of heavy hydrocarbons from a reservoir. More particularly, from a knowledge of the steady flow rate of addition of the diluent m_dil, it is possible to then calculate the production rate of heavy hydrocarbons from a reservoir m_hydrocarbons from the equation m ydrocarbons ⁼ (1/C— 1 ).

It can therefore be seen that this process is a quick, cheap and simple procedure that enables the allocation of production rates to individual reservoirs on an oilfield.

Unlike the expensive and/or inaccurate processes known in the art (e.g. multiphase meters, routing of wells to a test separator and calibration of flow rates based on RPM on a downhole pump), the process for the allocation of production rates of the present invention has none of these drawbacks, as it is typically able to make use of lines already present in established wells (e.g. chemical injection lines or emulsion breaker lines for the diluent, although it is also possible to use umbilicals specifically for the diluent) and it is quick to run, and is accurate and inexpensive, something that is very important in view of the potential cost implications discussed in the introduction.

In the fourth aspect of the present invention, a system is provided for measuring the production rate of heavy hydrocarbons from a reservoir, said system comprising:

Element (i) of the system is, of course, standard for productions wells used to recover heavy hydrocarbons from reservoirs. The means that enables recovery of the heavy hydrocarbons may be any means that is suitable for this task; there are many known in this field, including steam assisted gravity drainage. Although in some instances it may be possible to recover the heavy hydrocarbons under the natural pressure of the system alone, in most cases it is necessary to assist recovery by the provision of an artificial lift, for example a downhole pump . Suitable pumps are well known to those in the art. Examples include electric submersible pumps, gas lift pumps, rod pumps, hydraulic pumps and progressive cavity pumps (see, for example, R. Fleshman, Oilfield Review, Spring 1999, pp. 49-62). Down hole pumps are very commonly used in heavy hydrocarbon wells, e.g. incorporating electric submersible pumps. Suitable pump capacities range from, for example, 500 m³/d to 5000 m³/d.

As discussed earlier in relation to the method, the means for adding a diluent to the heavy hydrocarbons in the production line downstream from the reservoir [i.e.

element (ii) of the system] may be means that is suitable for injecting the diluent into the heavy hydrocarbons. Preferably, the means for adding a diluent to the heavy hydrocarbons in the production line should be means that allow a "retrofit installation" by making use of a line feeding into the production line that is already present in the existing well comprising the reservoir. Thus, the means by which the diluent may be added to the heavy hydrocarbons in the production line downstream from the reservoir can, for example, be an existing injection line into the production line, e.g. a chemical injection line or an emulsion breaker line.

Preferably, the means for adding diluent to a hydrocarbon production line comprises a pump that is able to deliver the desired flow rate used in combination with a calibrated flowmeter and, optionally, a control system, and preferably the means comprises a displacement pump used in combination with a calibrated flowmeter, e.g. membrane pumps obtainable from Lewa.

The means for removing the sample of a homogeneous mixture of the heavy hydrocarbons and the diluent from the hydrocarbon production line formed after the addition of the diluent can be any suitable means for the purpose. Again, as for the means for adding a diluent described and exemplified above, ideally it should be inexpensive and simple in construction and preferably will make use of an existing line attached to the production line downstream from the point of addition of the diluent by the diluent addition means, e.g. using a line attached to the production line upstream from the production manifold.

In one preferred embodiment of the system of the invention, the means for removing the homogeneous mixture of the heavy hydrocarbons and the diluent from the hydrocarbon production line is operated at atmospheric pressure.

The means for removing the sample of a homogeneous mixture of the heavy hydrocarbons and the diluent from the hydrocarbon production line formed after the addition of the diluent in the system of the present invention may have incorporated into it a viscometer to measure the viscosity of said sample. This may preferably be a temperature-controlled viscometer. The viscometer could, for example, be rotational or oscillatory viscometer (e.g. Anton Paar viscometer) with a thermoelectric temperature controlled measure chamber such as (e.g. Peltier temperature controlled measure chamber) and a measure bob suited for viscous oils. Furthermore, because of advances in the development of online viscometers, it is also possible to adapt the system so that an online viscometer is incorporated to give online measurements.

As discussed in the introduction, existing methods for rate allocations for heavy hydrocarbons are expensive, time consuming and unreliable. The method, uses and system of the present invention address these issues, as they require a minimum of equipment and investment for retrofit installation, and they would be very simple for greenfield installations.

Significant advantages that have been shown as a result of the present invention over existing methods include: it is very simple, and can be used by any operator with background and skills at a level of the ordinary skilled man in the field of heavy hydrocarbon recovery; it is easy to calibrate, with only small samples needed; there is no need for vendors with complicated and expensive instruments; it can be used to calibrate other conventional methods and instruments for the allocation of the production rates of heavy hydrocarbons; the system of the invention is easy to retrofit on existing production sites (e.g. for reservoirs on the existing Peregrino field); and it may be incorporated online for some greenfield installations (e.g. for reservoirs on the planned Mariner and Bressay fields).

Brief Description of the Drawings

The invention is diagrammatically illustrated, by way of example, in the accompanying drawings in which:

Figure 1 is a plot of the viscosity of a heavy oil (Bressay 3/28a-6) at a constant temperature (37°C) at varying concentrations of a diluent (Asgard blend) versus shear rate;

Figure 2 is a plot of the viscosity of homogeneous blends of a heavy oil (Bressay 3/28a-6) with varying concentrations of a diluent (Asgard blend) against temperature;

Figure 3 is a calibration curve for a heavy hydrocarbon reservoir (Bressay 3/28a-6) of the viscosity of homogeneous mixtures of the heavy hydrocarbons from the reservoir at various dilutions of diluent against the concentration of diluent as a percentage by volume in the homogeneous mixtures of the heavy hydrocarbons from the reservoir and the diluents, measured at 25°C and 1 atmosphere; and Figure 4 is a schematic illustration of a system according to the present invention for determining the production rate of heavy hydrocarbons from a reservoir.

Examples

The present invention may be further understood by reference to the following, non- limiting examples.

Example 1

In this example, the effect of introducing varying concentrations of a diluent on the viscosity of a heavy oil at a constant temperature (37°C) were studied.

The diluent used in this example was Asgard blend. Asgard blend is a commercially available light, low sulphur, North Sea crude oil. It consists of Asgard Crude, Asgard Condensate, and Kristin Crude. Characteristics of the new crude blend are: gravity, 48.9°; specific gravity, 0.7842; sulphur content, 0.08 wt.%; pour point, -27°C; total acid number, <0.01 mg potassium hydroxide /g; nickel, <0.1 ppm (wt); vanadium, <0.1 ppm (wt); viscosity at 20°C, and 1 .63 cSt.

Its full composition details are provided at the following website link: http://www.statoil.com/en/OurOperations/TradingProducts/CrudeOil/Crudeoilassays/ Downloads/Asqard%20blend%202012%2006.pdf

The heavy oil was Bressay 3/28a-6 which has an ΑΡ of 1 1 -12, a sulphur content of 0.8 wt%, a total acid number of 8.0 mg potassium hydroxide/g, a pour point of 7°C (42°F) and 1 .2 wt% asphaltene. The concentrations by vol% in the final

homogeneous mixture of heavy oil and diluent were 0%, 1 %, 2% and 5%. The viscosity of the homogeneous mixtures of heavy oil plus diluent at a constant pressure of 100,000Pa (1 bar) were measured using an Anton Paar rotational viscosimeter

It can be seen from the results as set out in Figure 1 that the addition of even a small amount of diluent results in a large reduction in the viscosity of the heavy oil plus diluent mixture. For example, increasing the concentration of diluent from 1 % to 2% results in a reduction in viscosity of over 1 ,000 mPa.s. Increasing the concentration of diluent from 2% to 5% results in a further reduction in viscosity of almost 50%. Example 2

In this example the effect of temperature on the viscosity of mixtures of heavy oil plus diluent with varying concentration of diluent was studied. Bressay 3/28a-6, as used in Example 1 and varying concentrations of Asgard blend (again as used in Example 1 ) were used, and the effects of temperature on viscosity of the mixture at a constant pressure of 100,000Pa (1 bar) were measured using an Anton Paar rotational viscosimeter .The concentrations by vol% in the final homogeneous mixture of heavy oil and diluent were 9%, 15%, 18%, 20% and 30%. The results are shown in Figure 2.

It can be seen from the results that the viscosity of these relatively high diluent concentration mixtures is strongly dependent on temperature, as exemplified across the range of 20 to 40 °C. Knowledge of this can be used for measurement of the production rates of heavy hydrocarbons from future wells and hence rate

allocatations for wells in fields of interest where it is intended to inject a high concentration of diluents (e.g. 5-20% upstream of the ESP).

It should be further noted that the results show that at lower temperatures the viscosity difference between heavy hydrocarbon samples containing the different concentrations of diluent is greater than the viscosity differences at higher temperatures. As a result, it can be seen that at lower temperatures the resolution, and hence the accuracy of the measurement, will be better. This is of particular importance when, for example, existing small diameter emulsion breaker pipes are used for injection of the diluent upstream of the heavy hydrocarbon reservoir.

Example 3

In this example the preparation of a calibration curve for use in the present invention is described.

The viscosity of a dead oil sample from a heavy hydrocarbon reservoir is measured at a pressure of 1.01325 x 10⁵ Pa (1 atmosphere) and a temperature of 25°C. The heavy oil used for this example was Bressay 3/28a-6, as used in Example 1 together with varying concentrations of diluent. Samples containing the dead oil sample and from 0.5 - 20% by vol% of diluent in the final homogeneous mixture of heavy oil and Asgard blend diluent are prepared by heating the samples to a temperature which is sufficiently high to homogenize the sample. The homogenization temperature is dependent on the diluent used. In this example, the diluent used is a condensate with a small fraction with a boiling point below 90°C, and the homogenization temperature used was 90 °C. The results of the viscosity measurements were repeated a number of times. The figures in Table 1 are calculated from a fitted curve/function [vol% = -4.598 In (viscosity) +43.96] derived as a result.

Table 1

These values are plotted in a graph, and the empirical function is fitted to the data as noted above. This graph and the associated empirical function together comprise the calibration curve for that particular heavy oil and diluent mixture. The graph is shown in Figure 3. From this calibration curve for the particular heavy hydrocarbons obtained from a reservoir at different concentrations of a given diluent at fixed temperature and pressure, it is possible to determine the production flow rate of the heavy hydrocarbons, as is shown below in Example 4. Example 4

In this example, the determination of the production rate of heavy hydrocarbons obtained from a reservoir using a calibration curve such as the one exemplified in Example 3 is described.

Figure 4 is a schematic illustration of a system according to the present invention for calculating the production rate of heavy hydrocarbons 2 from a reservoir 1 (in this case Bressay 3/28a-6 as used to prepare the calibration curve for the same reservoir). The heavy hydrocarbons 2 are recovered from the reservoir 1 by natural drainage via a production line 4 to a wellhead 3. In this example, a downhole pump 7 is incorporated in the production line 4 to assist recovery of the heavy hydrocarbons.

The system of the invention is constructed to include an injection system for the injection of the diluent, for example Asgard Blend, at an appropriate point in the production line 4 downstream from the reservoir 1 and upstream from the wellhead 3, the diluent being that used in Example 3 in the preparation of the calibration curve. In the present example, an existing injection line 5 downstream from the reservoir 1 and upstream of the downhole pump 7 is utilised to inject the diluent into the heavy hydrocarbons recovered from the reservoir 1 , the line being injected into the production line 4. Alternative suitable points of addition downstream from the reservoir 1 and upstream from the wellhead 3 include injection via an existing injection line 5 into the heavy hydrocarbons in the production line 4 upstream of a gas lift valve.

The production can be both oil and water continuous; in this instance the production was water continuous. A pump 6 controlled by a flowmeter added the diluent in the form of condensate from the Bressay field into the well at a constant flow rate which was sufficient to create a steady state composition from the injection point to the wellhead. The pump 6 is a displacement pump used in combination with a calibrated flowmeter. In the present example, the rate of addition of diluent into the well that is required is found to be 13.1 m³/h over 1 hour.

After allowing a sufficient time to allow the diluent and the heavy hydrocarbon to form a homogeneous mixture (about 500 seconds after mixing in transport) a sample 8 of the homogeneous mixture obtained is removed from the production line 4 at a point upstream of the wellhead 3. When taking samples from a water continuous flow, it is difficult to determine the correct water cut inside the tube, so the sample will be an arbitrary mix of oil and water.

Gas and bulk water is separated from the sample, and dispersed water in the oil phase is separated by centrifuging the sample at 90°C (i.e. the sample preparation temperature for this heavy oil and diluent mixture) in a bench-size centrifuge 9.

Other methods, such as the use of a bench-size electrostatic coalsecer could also be used to remove the dispersed water.

The remaining water concentration in the oil sample is then determined by, for example, Karl-Fisher titration.

The oil is transferred to a temperature-controlled viscometer 10, and the viscosity is measured at 25°C and 1 .01325 x 10⁵ Pa (1 atmosphere), the same conditions of temperature and pressure used to prepare the calibration curve for the oil-diluent curve of the reservoir 1 of interest. The viscometer 10 is in this case made by Anton Paar and had a Peltier temperature controlled measure chamber and a measuring bob suited for use with viscous oils.

If the water content in the prepared sample is significant, as is the case in the present example, the viscosity value may be corrected for water concentration using, for example, the Brinkman equation. The corrected value (in this example, 4577 cP) is then matched to the calibration curve for the well, as prepared in Example 3 and shown in Figure 3, and the heavy hydrocarbon production rate for the reservoir 1 was determined from this as follows.

The heavy hydrocarbon production rate is calculated from equation (1 ) below: m ydrocarbons ⁼ (1/C— 1 ) (1 ), wherein m_nydrocarbons is the production rate of heavy hydrocarbons to be determined, m_dii is the flow rate of addition of the diluent to the heavy hydrocarbons in step (ii) of the method according to the first aspect of the present invention, and c is the diluent fraction.

The diluent fraction c is determined by the following steps:

(i) comparison of the viscosity (corrected for water content if it is significant) measured above to the calibration curve of the viscosity in Figure 3 prepared in Example 3 to give the corresponding concentration of the diluent as a percentage by volume in the homogeneous mixture of the heavy hydrocarbons from the reservoir and the diluents in the homogeneous mixture as determined from the curve; and

(ii) conversion of the concentration thus obtained to a fraction to give the desired diluent fraction c.

In the present example, the viscosity of the homogeneous mixture of heavy hydrocarbons and diluent, as corrected for water content, is measured at 4577 cP. The constant diluent flow rate, m_dil, added to the heavy hydrocarbons in the production line 4 via injection line 5 using the pump 6 is, as noted above, 13.1 m³/h. From the calibration curve, the concentration of the diluent as a percentage by volume in the homogeneous mixture of the heavy hydrocarbons was determined to be 5.204382 vol%. Converting this to a diluent fraction c gave a figure of c = 0.052044.

Thus, knowing m_d/,and c, it is possible from equation (1 ) above to calculate the heavy hydrocarbon production rate m_hydrocarbons for the reservoir 1 to be 238.61 1 m³/h.

Claims

1 . A method for measuring the production rate of heavy hydrocarbons from a reservoir, wherein said reservoir having said heavy hydrocarbons therein is connected to a production line that enables said heavy hydrocarbons to be recovered, said method comprising the following steps:

(i) the addition of a diluent at a constant flow rate to said heavy hydrocarbons in said production line downstream from said reservoir;

(ii) the provision of sufficient time for said diluent and said heavy hydrocarbons from said reservoir to mix homogeneously; and

2. The method according to claim 1 , wherein the viscosity of said diluent is lower than the viscosity of said heavy oil.

3. The method according to claim 1 or claim 2, wherein the viscosity of said diluent is from 0.1 to 7500 mPa.s, more preferably from 0.1 to 100 mPa.s and most preferably from 1 -10 mPa.s at 37°C.

4. A method as claimed in any one of claims 1 to 3, wherein the amount of diluent added to said heavy hydrocarbons in said production line is from 0.01 -50% by volume of the resulting mixture and preferably from 5-20% by volume.

5. A method according to any of claims 1 to 4, wherein the addition of said diluent to said heavy hydrocarbons in said production line is upstream of a downhole pump.

6. A method according to any of claims 1 to 4, wherein the addition of said diluent to said heavy hydrocarbons in said production line is upstream of a gas lift valve.

7 A method according to any of claims 1 to 4, wherein the addition of said diluent to said heavy hydrocarbons in said production line is upstream at a transport distance to allow sufficient mixing intensity to make a homogenous fluid of the diluent/crude oil mixture.

8. A method according to any of claims 1 to 7, wherein the means by which said diluent is added to said heavy hydrocarbons in said production line downstream from said reservoir is an existing injection line into said production line, preferably a chemical injection line, an emulsion breaker line, or an umbilical specifically for said diluent.

9. A method as claimed in any one of claims 1 to 8, wherein said diluent comprises C4-30 hydrocarbons.

10. A method as claimed in any one of claims 1 to 9, wherein said diluent is selected from the group consisting of naphtha, light or medium light crude oil, diesel, natural-gas condensate, synthetic crude and a mixture thereof, and is preferably diesel or natural-gas condensate or a mixture thereof.

1 1 . A method according to any one of claims 1 to 10, wherein said diluent is added to said heavy hydrocarbons in said production line by means of a pump that is able to deliver the desired flow rate used in combination with a calibrated flowmeter and, optionally, a control system, and preferably by means of a displacement pump used in combination with a calibrated flowmeter.

12. A method according to any one of claims 1 to 1 1 , wherein said method is conducted at a temperature of from 0°C to 250°C, preferably from 30°C to 90°C, most preferably from 0°C to 20°C or 20°C to 40°C.

13. A method according to any one of claims 1 to 12, wherein said production rate of heavy hydrocarbons is calculated from the equation m_hydrocarbons = m_dil (1 /c - 1 ) wherein m_hydrocarbons is the production rate of heavy hydrocarbons to be determined, m_dii is the flow rate of addition of the diluent to the heavy hydrocarbons in step (ii) of the method, and c is the diluent fraction.

14. A method according to claim 13, wherein the diluent fraction c of the diluent is determined by the following steps:

(i) the measurement at a fixed temperature and pressure of the viscosity of the sample of the homogeneous mixture obtained in step (ii) at the second point on the production line downstream from the point of addition of said diluent in step (iii) of the method; (ii) comparison of the viscosity measured in step (i) to a calibration curve of the viscosity of homogeneous mixtures of heavy hydrocarbons from said reservoir at various dilutions of diluent against the concentration of diluent as a percentage by volume in said homogeneous mixtures of said heavy hydrocarbons from said reservoir and said diluents, to give the concentration of the diluent in the

15. A process according to any one of claims 1 to 14, further comprising the step of removing water from said sample before determining the viscosity of the sample of the homogeneous mixture obtained in step (ii).

16. A process according to claim 15, further comprising the step of determining the remaining water content of the sample of the homogeneous mixture obtained in step (ii) after removing water from the sample, and then correcting for water content the viscosity measurement of said sample of the homogeneous mixture obtained in step (ii).

17. Use of a viscosity calibration curve of homogeneous mixtures of heavy hydrocarbons recovered from a reservoir by means of a production line and a diluent added at different concentrations to said production line at a constant flow rate to determine:

18. Use of a viscosity calibration curve for a heavy hydrocarbon reservoir for measuring the production rate of heavy hydrocarbons from a reservoir.

19. A system for measuring the production rate of heavy hydrocarbons from a reservoir, said system comprising:

20. A system according to claim 19, wherein the means for adding diluent to a hydrocarbon production line comprises a pump that is sufficient to deliver the desired flow rate used in combination with a calibrated flowmeter and, optionally, a control system, and preferably the means comprises a displacement pump used in combination with a calibrated flowmeter.

21 . A system according to claim 19 or claim 20, wherein the means for removing said homogeneous mixture of said heavy hydrocarbons and said diluent from said hydrocarbon production line is operated at atmospheric pressure or in a pressure cylinder at a pressure of greater than atmospheric.

22. A system according to any one of claims 19 to 21 , wherein said system is used to measure the viscosity of said sample of said homogeneous mixture of said heavy hydrocarbons and said diluent.

23. A system according to claim 22, comprising a viscometer to measure the viscosity of said sample, preferably a temperature-controlled viscometer.