001.0 Intro to Sampling

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. Introduction to Sampling 1.0 Revision 4

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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.

Displa cement Direction r2

r1

O il

W a ter

W a ter

L Sma ll p c La rge ra dius

La rge p c Sma ll ra dius

? Pflow ? ? Pcapillary ? Pflow ?

?P *L ?L

1 1 ? Pcapillary ? 2? cos? ( ? ) r1 r2 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. 1.0 Imbition

kr = k / k

krg

kro

0

1.0 Sgma x

Sgc Residual Gas Saturation

(=1-Swi)

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: Liquid pha se of va rying com positions Ga s pha se bubbles p>>p b

p>>p b

Vicinity of w ellbore

Reservoir

Phase distribution and mobility during flow (a) Introduction to Sampling 1.0 Revision 4

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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. Liquid pha se of va rying com positions Ga s pha se bubbles p

p>p b

pb

Vicinity of w ellbore

Reservoir

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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Liquid pha se of va rying compositions Ga s pha se bubbles

p