001.0 Intro to Sampling

Introduction to Sampling 1.0 Page 1

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Introduction to Sampling Section

This training section is divided into the following topics:

Sampling Objectives

Applications of Fluid Analysis Data

Factors affecting Representative Sampling

Selecting a Sampling Method

Bottomhole Sampling

Surface Sampling

Sampling Objectives

Ideally, the aim of reservoir fluid sampling is to provide the PVT laboratories with small volumes of fluids under pressure which would, either directly or after recombination, lead to a sample which is representative of the overall hydrocarbon fluid that fills the pores of the formation. Coring and logging programs can normally continue throughout the development of a reservoir because data obtained from the last well is often of equal value to that obtained from the first. Unfortunately, this is not the case for reservoir fluids. Due to the change in phase behaviour that occurs once the pressure in the formation reaches the saturation pressure, sampling should be performed at the very earliest stage of the field’s production history and preferably before the downhole average pressure falls below its initial value Pi. This condition has best chance of being satisfied while testing exploration and appraisal wells, which by definition, are the first wells to penetrate hydrocarbon deposits and are normally only produced for a limited period of time.

Experience from the Beryl field, a giant field in the North Sea, underlines the importance of a thorough evaluation of PVT properties. In that case, initial plans to construct a platform and the associated production facilities were based on the fluid properties of samples recovered from the first two wells. These plans had to be changed, at considerable cost, when further evidence showed that the reservoir oil was much more volatile than originally anticipated1.

Since erroneous reservoir fluid data can be so costly to the operator it is clear that both the sampling and analysis must be conducted with the utmost care. Sampling is probably the most delicate of field operations since it requires not only solid experience in open hole logging or well testing, but a also a thorough understanding of reservoir engineering, and well behaviour problems.


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Applications of Fluid Analysis Data

Almost all engineering and economic studies related to oil and gas production operations depend on an understanding of the behaviour of the reservoir fluids. An important concern of every petroleum engineer, therefore, is the quality of the fluid data upon which these studies are based. Reservoir engineering studies, which are performed using PVT analysis data, are always made on the basis of the reservoir at its initial conditions.

While reservoir engineers generally have the greatest claim on such information, reservoir fluid analyses are also valuable to geologists, production specialists and many others. The following table gives a general indication of the principal applications of this data in the main petroleum engineering disciplines. Among others, they include the evaluation of electric logs and well test, the estimation of the volume of the original oil in place (OOIP), the design of the production facilities, the determination of the commercial value of the crude oil to be produced, material balance and reservoir simulation calculations, improved recovery project design etc.

Discipline Applications

Reservoir Engineering

Reserve estimation, material balance calculations, fluid flow in porous media, natural drive mechanisms, well test design and interpretation. Design of secondary and tertiary recovery projects. Displacement efficiency.

Production Engineering Completion design, material specification, artificial lift calculations, production facilities design, production log interpretation, production forecasts,

Facilities/Process Engineering Design proposals for separation, treating, metering and pipeline facilities. Final facility operation. Flow assurance

Geology Reservoir correlation, Geochemical studies, Hydrocarbon source studies

Refining & Product Marketing Product Yield and Value

Environmental Engineering Disposal and environmental impact studies

Applications of Reservoir Fluid Analysis Data


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Factors affecting Representative Sampling

Reservoir effects

In designing a sampling procedure, we must consider the effect that the producing conditions will have had on the reservoir fluids we are sampling. When the well is put to flow, the expansion of the flowing fluid in the vicinity of the wellbore causes a pressure drop which propagates throughout the formation causing, in its turn, the expansion of the fluid further out. When the pressure in an oil reservoir drops below the bubble point, gas comes out of solution and forms a separate phase. Similarly, when the pressure in a gas condensate reservoir drops below the dew point, liquid begins to condense in the reservoir.

In either case, the minor phase must build up to a critical saturation and develop sufficient phase continuity before it begins to flow. A gas bubble or a liquid droplet needs to develop a certain size in order that the pressure drop applied across it, due to flow in the wellbore, manages to overcome the capillary pressure difference as in the following diagram. In the meantime, the composition of the produced fluid is altered by the selective loss of light or heavy hydrocarbons.

Displacement Direction

W aterW ater

L

Small pc

Large radiusLarge pc

Small radius

r2 r1

Oil

)11

(cos2

*

21 rrP

LLP

P

PP

capillary

flow

capillaryflow

???

??

???

??

??

Conditions for liberating trapped bubbles/droplets due to capillary entrapment


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Typical values of the critical saturation for the flow to occur vary between 10-20% for the oil phase and 5-10% for the gas phase. The position of the reservoir temperature isotherm with respect to the fluid’s phase envelope determines how quickly, in terms of time-dependent pressure drop, the second phase will attain its critical saturation. It can vary from a few psi for a near critical oil to a few hundred psi for a black oil system. In the PVT laboratory, a 0-60% change in gas saturation has been observed for a pressure drop of the order of 5 psi. The critical phase saturations are also referred as “end point saturations” in the two-phase relative permeability curve plots.

Sgma x

1.0

kr =

k/k

0Sgc

1.0

Residual GasSaturation

(=1-Swi)

kro

krg

Imbition

Gas Oil relative permeability curves

In a simple single well reservoir model (Figure a) cylindrical flow dictates a pressure distribution out from the wellbore which can be divided in two sectors:

p>>pb p>>pb

Vicinityof w ellbore Reservoir

Liquid phase ofvaryingcompositions

Gas pha sebubbles

Phase distribution and mobility during flow (a)


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1. A sector near the wellbore where pressure gradients due to flow are high.

2. A sector in the reservoir beyond the first where pressure gradients due to flow are low.

As long as the fluid remains monophasic, everywhere in the zone the composition is the same and identical to the original one.

Once the second phase starts to drop out, the composition of the produced and of the remaining fluids in the reservoir are altered by the selective distribution of the individual components in the two streams. As the downhole flowing pressure drops slightly below the saturation point (Figure b), small bubbles (droplets for gas condensates) of the minor phase are released but remain rather isolated from each other inside the network of the porous media.

p pb p>pb

Vicinityof w ellbore

Reservoir

Liquid phase ofva ryingcompositions

Gas phasebubbles

Phase distribution and mobility during flow (b)

As they have not obtained saturation values high enough to allow them to flow, they remain in the formation whereas the mobile phase composition is now poorer (richer for gas condensates) in light and intermediate fractions. This phenomenon explains the slight reduction in the producing GOR that is often reported during production from oil reservoirs and which lasts for a short period of time before it starts picking-up again.

While the condensed phase in a gas condensate may never attain its critical saturation to flow, the gas saturation in an oil reservoir will almost certainly reach a point where gas flow will occur. Once this critical saturation has been attained (Figure c), the flow of the gas phase will increase rapidly because of its relatively low viscosity and thereby increase its contribution to the total production.


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p<pb p<pb

Vicinityof w ellbore

Reservoir

Liquid phase ofvaryingcompositions

Gas phasebubbles

Phase distribution and mobility during flow (c)

The GOR will typically rise and will attain a maximum value before, after a long producing time, it will follow a soft declining trend once the remaining in-situ fluid has been stripped from its light end. Nevertheless, Serra et al7 could not verify in their work that in all cases of oils with bubble points close to the flowing pressure the GOR started increasing when the gas saturation around the wellbore obtained values higher than its critical one.

Time

Rsi

Pre

ssu

re,

Rs

PressureDecline

ProducingGOR

Pb

pi

W ater Cut (%)

Typical patterns of the GOR and pressure evolution during production from an oil reservoir


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Near Wellbore Effects

Even if these phenomena are not reservoir-wide, the pressure drawdown associated with flow will often be sufficient to drop the pressure of the fluid in the immediate vicinity of the wellbore below its bubble point or dew point pressure and into the two-phase region, as illustrated below.

Pressure and phase distribution

A sample of such fluid will not be representative of the original reservoir fluid existing farther out in the reservoir and thus it will not be suitable for sampling and PVT analysis.

Steps must be taken to determine the reservoir pressure, temperature, and the general category of the reservoir fluid. If the relationship between reservoir pressure and bubble point or dew point pressure can be estimated, steps can be taken to ensure that the sampled fluid is representative.


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Variation of original fluid properties within the reservoir

Another concern in obtaining a representative sample is the degree of variation in the original reservoir fluid throughout the reservoir. Reservoirs having thick vertical hydrocarbon columns, high dip angle and adequate vertical permeability can show significant variations of the oil composition with depth. It is known that under special conditions gravity forces can induce variations in composition along the hydrocarbon column. Variations such as these cannot be ac-counted for in one specific sample. A pattern must be established from several samples or producing characteristics, from various wells, completed at different intervals.

Typical examples of this type of behaviour reported in the literature are the Birba Field, in South Oman, and Anschutz Ranch East Field, located in the western Overthrust Belt along the Wyoming/Utah border2,18. In the former, PVT analysis of a sample recovered from a well at the lower part of the crest showed a bubble point pressure of 6900 psia and the presence of a C7+ fraction with a relatively high molecular weight. A second sample that was taken from another well 212m shallower gave a gas condensate although reservoir pressures indicated that this gas was in communication with the oil. In the latter, the discovery well tested four different sets of perforations, which produced gas condensate fluids with different compositions, GORs and saturation pressures.

Reservoir temperature

Attention should be paid to the accurate determination of the bottom hole temperature when sampling reservoir fluids that are suspected to be near-critical fluids. An error of even a few degrees Fahrenheit could be enough to cross the phase envelope from gas condensate to volatile oil during the subsequent PVT study. This could have serious implications on the viability of a project which often depend on the classification of the reservoir fluid for fiscal or OPEC quota purposes.


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Timing

Timing is an important consideration in obtaining a representative sample of the original reservoir fluid. Obviously, it makes sense to sample as early in a reservoir’s producing life as possible. Once production creates significant volumes of free gas on a reservoir-wide basis, obtaining a sample of the original fluid may be impossible. Often, a reservoir fluid sample will be taken as part of a well testing procedure that immediately follows the completion of the first well in a reservoir. An example would be a newly discovered field where development plans may rely on the early determination of expected reserves and production rates. In such cases, it is important that the new well be cleaned up before sampling to remove all traces of drilling fluid from the well and the near wellbore.

Selecting a Sampling Method

In general, one has a choice of taking monophasic samples close to the formation with bottomhole sampling tools or sampling the separated streams of oil and gas at the surface and recombining them later in the laboratory to obtain a representative reservoir fluid sample. The choice of sampling technique is influenced by:

o The volume of sample required for analysis.

o The type of reservoir fluid to be sampled.

o The degree of reservoir depletion.

o The surface process and well completion design.


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Bottomhole Sampling

Bottomhole sampling is the trapping of a volume of fluid at reservoir conditions in a pressure vessel run in the well close to the productive interval, either suspended on wireline or in the DST string. This sampling method is used exclusively during openhole logging and is the most effective technique during cased hole operations such as exploration well testing or production testing, when reservoir flowing conditions permit. Bottomhole sampling applies when:

o the flowing bottom hole pressure is believed to be greater than the reservoir fluid saturation pressure.

o the subsurface equipment or nature of the fluid (e.g. API<10) will not prevent the sampler from reaching the appropriate depth or make its retrieval difficult.

o relatively small volumes of fluid are required for analysis.

o an asphaltene study is required.

Surface Sampling

During exploration well testing and production testing it is possible to obtain representative surface samples from various locations such as the wellhead, choke manifold or test separator depending on the fluid properties and flow conditions. Surface sampling upstream of the separator requires the wellhead pressure be above saturation pressure using conventional sampling techniques or at least homogeneous for specialised techniques such as Isokinetic sampling.

By far the most common surface sampling technique is separator recombination sampling. This involves taking simultaneous samples of separator oil and gas, along with accurate measurements of their relative production, and reconstructing a representative sample in the PVT laboratory.


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Surface sampling is routinely used as a back-up to a good quality bottomhole sample but may be the primary source of samples when:

o a large volume of both pressurised oil and gas are required for analysis (e.g. EOR study)

o bottomhole flowing conditions are less than saturation pressure or there is a high water cut such that the fluid in the hole may not be representative.

The main challenge in separator recombination sampling is ensuring the accuracy of the separator flow measurements and stability of separation conditions before and during sampling. The separator liquid and gas are in dynamic equilibrium. Any drop in pressure or increase in temperature of the separator liquid, which is at its bubble point, will result in the formation of gas. For the separator gas, which is at its dew point, any increase in pressure or decrease in temperature will result in the condensation of heavy components.

Generally, a bottomhole sample is preferred, if gas and oil surface measurement capabilities are in question. However, if they are reliable, the surface sampling technique can give a statistically valid value of GOR measured over a long period of time.

Isokinetic gas sampling at the separator gas outlet line is occasionally performed to determine the amount of liquid carryover in the separator during high flowrate gas condensate testing. This liquid, which would otherwise go unmeasured, can be a very significant proportion of the total liquid in a lean gas condensate.

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001.0 Intro to Sampling