SPE-164593-MS

SPE 164593

Formation Testing and Sampling in Low Mobility Heavy Oil Formations of the Eastern Desert, Egypt Jeff Edelman, Transglobe Energy; Shabbir H. Shah, Peter Weinheber, Ramy Ahmed, Izzat Roumani, Schlumberger; Karim Maghrabia, Petrodara

Copyright 2013, Society of Petroleum Engineers

This paper was prepared for presentation at the North Africa Technical Conference & Exhibition held in Cairo, Egypt, 1517 April 2013.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract The Arta fields of Egyptian Eastern Desert are operated by Petrodara, a joint venture of Transglobe Energy and Egyptian General Petroleum Corporation (EGPC). The main producing horizon is the Nukhul and formation pressure measurements are critical in this poorly sorted conglomerated marl in order to understand and model depletion. However, low permeability and high viscosity oils contributed to a very low mobility environment that presented considerable challenges to Wireline Formation Tester (WFT) tools. Extensive testing programs resulted in an excessive amount of tests that were unusable, being classified as dry, tight or supercharged. This low mobility environment also complicated the requirement for PVT samples acquired with the WFT tools. Normal testing operations resulted in very high drawdowns that sampled below formation pressure and caused emulsions with the filtrate of the water based drilling fluid.

In this paper we discuss how the Operator and the Service Company combined to employ fit for purpose WFT techniques

to acquire accurate formation pressure data and PVT quality oil samples. Most of our discussion will be based on understanding the dynamics of pretesting in low permeability formations and how the optimal tool and pretest design can produce results where previous attempts have failed. Specifically we consider the newest pretest only WFT that provides very fine control over pretest rate and volume and allows precise test design that is not possible with conventional WFT tools. Additionally, we demonstrate the application of best practices and lessons learned from worldwide sampling operation to acquire PVT quality heavy oil samples. Introduction The Arta field in the Egyptian Eastern Desert produces mainly from the Nukhul Formation that is characterized as a complex, thin-bedded sequence with heterogeneous laminated siltstone. Typical reservoirs show low-to-average permeability, low temperatures and moderately heavy oil in the 17-24 degree API range. The Nukhul Formation represents the early rift sequence of the Gulf of Suez rift basin. It is underlain by the Thebes Eocene carbonates of the Pre-Rift sequence and overlain by a thick succession of predominantly fine-grained marine clastics of the synrift Rudeis Formation. The Nukhul Formation in Arta field is subdivided into two sections: the Lower Nukhul, which is composed mainly of conglomeratic sandstone with some shale and limestone streaks and the Upper Nukhul which comprises a vertically stacked conglomerate, occasionally sandstone, and sandy limestone lithofacies. The limestone facies is more common within the Upper Nukhul and it represents a tidal-dominated estuarine facies within marginal marine realm deposited in a low to moderate energy setting. The deposition of Nukhul formation records a finning-upward rhythmic sedimentation represented by sequences of tidal channel and estuarine channel fill sandstone. These sediments were deposited on the paleo-low relief areas of the Thebes unconformity. (Edelman 2013)

The Lower Nukhul has higher porosity and permeability, which is supported by water injection and generally does not

require stimulation. The upper Nukhul has porosity ranging from 5 to 18% with an arithmetic average of 13% and a mean of 12%. Permeability ranges from 0.003 mD to 12.8 mD with an arithmetic average of 1.5 mD and a mean of 0.6 mD. The reservoir requires hydraulic fracture stimulation to be economically productive.

*Mark of Schlumberger

It is the Upper Nukhul that has proved challenging for formation tester operations. Measured mobilities have ranged from 0.01 to 5 mD/cP and obtaining reliable formation pressure with conventional pretesting is very difficult. Many pretests end up

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Hydrostatic Pressure

Overbalance

Total Differential

Drawdown Formation Pressure

Flowing Pressure

being recorded as dry. However, with optimal tool and test design we were able to surmount these difficulties and record valuable formation pressure information.

Wireline Formation Tester The original wireline formation tester tools introduced in the 1950s had the sole objective of acquiring a sample of formation fluid. As a part of the tools operation a small pre-sampling test (the pretest) was performed to ensure a packer seal and that the formation was suitable for sampling. Unbeknownst to the original tool designers, the outputs of this pretest proved to be extremely valuable. A depth specific formation pressure could be determined and later work (Moran and Fiklea, 1962) derived formation mobility. Pretesting was able to deliver a series of pressure measurements over depth that allowed oil and gas operators to identify fluid types and contacts, characterize heterogeneities and anisotropy, determine vertical and horizontal connectivity across barriers, identify low resistivity pay zones, optimize production strategy and drainage mechanisms and many other applications.

The WFT tools in use today rely on the same principles of pressure measurement as the original tools from the 1950s. A

packer-probe assembly is pressed again the formation wall, the probe penetrates the mudcake and the packer forms a hydraulic seal against wellbore hydrostatic pressure. The packer probe assembly is connected by a flowline to a high precision crystal gauge. To initiate the pretest the volume of the flowline is increased by drawing down a pretest piston. The volume increase will reduce the pressure in the flowline from wellbore hydrostatic down to formation pressure. Further increase in flowline volume will reduce the pressure below formation pressure and will induce fluid flow from the formation into the tool. At the conclusion of the pretest the piston will stop and pressure in the flowline will build up and stabilize at formation pressure. In high mobility formations (over 10 mD/cP) this sequence proceeds smoothly and quickly. Typical pretest volumes of 5 to 35 cc will build up and stabilize at formation pressure with a few minutes. However, in low mobility formations, especially below 1 mD/cP, flow from the formation is very slow and long build-up times ensue. These long build-up times distort the pressure measurement as well as increase operational risk: the longer the WFT remains stationary in the wellbore the greater the chances of the tools becoming stuck and necessitating an expensive and time consuming fishing operation.

To understand how to improve on this we look closely at the fundamentals of the pressure measurement, what the sequence

of the test is and what elements affect the tool capability for pressure measurement. This has been detailed elsewhere (Weinheber, 2008) and is summarized here. The terminology we use is explained in Fig. 1.

Hydrostatic Pressure the pressure in the mud column at any given depth. This is a function of the mud weight and the true vertical depth. Formation Pressure the static pressure at a given point in the reservoir. Overbalance Pressure the difference between the hydrostatic pressure in the wellbore and the formation pressure. Flowing Pressure the gauge pressure at the sandface while the pretest piston is drawing back (or the pump out is working) Drawdown pressure (delta P) the difference between the formation pressure and the flowing pressure. Total differential the difference between the flowing pressure and hydrostatic pressure. This is also equal to drawdown + overbalance pressure.

Figure 1: Pretesting nomenclature

We divide the pretest into multiple phases during a single complete cycle of pressure measurement: 1. Flowline decompression 2. After flowline decompression the drawdown will approach the steady state via an exponential 3. In the case of sufficiently long flowline period at a sufficiently low flow rate: steady state formation flow 4. Storage or tool dominated early time portion of the build-up 5. Formation (spherical and/ or radial) late time portion of the build-up

In the context of the above sequence, but now only considering low mobility formation, we frequently find ourselves

dealing with 1) flowline decompression, possibly 2) the exponential form of drawdown and 4) the early time exponential portion of the build-up. When these terms dominate, as they do in low mobility environment, they mask the formation response; whether it is the stable flowing pressure in the drawdown or the spherical and/or radial flow in the build-up. In every low mobility formation less than 0.01 mD/cP, we frequently find ourselves essentially dealing with drawdown that acts just like 1) above straight flow line decompression. That is to say the fluid flow rate in the tool after the flow line pressure drops

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below sand face pressure is inconsequential compared with the pretest piston rate. Consequently optimal acquisition of pretest data in the low mobility environment is focused on reducing the effects of the flowline decompression and of the exponential portions of the pretest. (Weinheber 2008)

The situation described above is encountered in the Nukhul formation of the Arta and East Arta fields. Most of the pretests

acquired were dry or tight and exactly similar response of 1) flowline decompression and 4) storage or tool dominated early time portion of the build-up were observed. The results shown in Fig. 2 and Fig. 3 represents 80% of the wireline formation testing results we were achieving prior to adopting optimized pretest volume and rates.

Figure 2: Dry Test example, Flowline decompression and storage response.

Figure 3: Tight Test example, storage or tool dominated early time portion of the build-up

Effect of flowline decompression in low mobility formations As discussed in the previous section, flowline decompression and fluid compressibility dominates in the pressure measurement of low mobility formations. The initial portion of the pretest is the flowline expansion (or decompression) to take the flowline pressure from wellbore hydrostatic down to sandface pressure. Flowline decompression has generally been taken to be the decompression of the fluid in the flowline and has been described by the following equation:

= ( + ) .. Eqn. 1

Where is the volume required to decompress a given flowline volume is represented by and is the flowline fluid

compressibility. The overbalance is the mud (wellbore hydrostatic) pressure minus the formation pressure ( ) and the pressure required to break the mud cake is . Note that the pressure required to break the mudcake is included in the equation but in reality has an insignificant impact on the overall result due to several reasons. Firstly as we shall see, it makes only a small mathematical difference. Secondly, most wireline tools consist of a probe-packer assembly and the mud cake is actually pierced and broken by the probe. The pretest drawdown does not break the mudcake as it has already been mechanically broken. Finally, laboratory work has indicated that it takes only the order of 10-100 psi of back pressure to break the mud cake.

Based on the above equation we calculated the volume required to decompress the fluid of MDT* and XPT* tools having

common probe types.

The table (Table.1) below is based on Eqn.1 and considers only the volume required to decompress the fluid in the flowline. However we cannot consider just the fluid compressibility, we must account for the total system compressibility.

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Consider example I in the table where 0.6 cc of decompression volume is calculated and compared to the MDT* pretest example in Weinheber, 2008. In the example a 1.8 cc pretest volume is required before the pressure in the flowline is brought down to the sandface pressure. This pretest was recorded under the exact circumstances on line I in the table. The extra 1.2 cc is required to account for the lack of flowline stiffness due to the compression required in the packer rubber, the tightening up of metal to metal seals, o-ring compression and etc.

Overbalance Flowline Volume Fluid Compressibility Volume to decompress

(PSI) (CC) (1/PSI) (CC) A 2000 XPT* with STD probe 70 Water 3 x 10

-06 0.4

B 1000 XPT* with STD probe 70 Water 3 x 10-06 0.2

C 500 XPT* with STD probe 70 Water 3 x 10-06 0.1

D 2000 MDT* with XLD probe 190 Water 3 x 10-06 1.1

E 1000 MDT* with XLD probe 190 Water 3 x 10-06 0.6

F 500 MDT* with XLD probe 190 Water 3 x 10-06 0.3

G 2000 XPT* with STD probe 70 Oil 7 x 10-06 1.0

H 1000 MDT* with XLD probe 190 Oil 7 x 10-06 2.7

I 500 MDT* with LD probe 154 Oil 7 x 10-06 0.6

Table 1: Fluid decompression volumes for various scenarios (ref SPE 115825)

From the table and the original formula it is seen that larger volumes, whether from flowline or probe, will require a larger pretest volume to decompress. Furthermore, in low mobility formations this volume will also partially determine the drawdown, p. This is because in low mobility formations the reservoir will not be able to provide fluid as fast as the pretest piston is moving. Pressure will continue to fall in the flowline until either some mechanical limit is reached or Darcy flow from the formation can sustain the p. Additionally, and most significantly, larger pretest volumes (below formation pressure) will result in significantly longer build-up times. This effect was modeled in Ecrin software and the results are presented in Fig. 4

This plot considers the time it takes to build-up

versus pretest volume. The vertical axis is difference between sandface pressure and flowline pressure; zero is indicating that the pretest has built-up completely to formation pressure. On the horizontal axis is the time of build-up, in this case from the beginning of the pretest. There are two points to note here: firstly, the larger volume tests start from a larger drawdown. The flowline significantly decompressed below formation pressure. Secondly, the noticeably longer time it takes to build-up, versus original pretest volume. Additional charts can be generated that show a dependence of build-up time on mobility, whether due to lower permeability or higher oil viscosity.

Figure 4: Ecrin modeling of build-up time vs pretest volume From the foregoing it is clear that low volume pretests will be the fastest to build-up to formation pressure. Furthermore it

is clear that low volume pretests can only be executed using a tool that has two important characteristics: a very low decompression volume and very fine control of pretest volume.

PressureXpress* Tool The XPT* (PressureXpress*) tool (Manin 2005) is specifically engineered for only pressure and mobility testing as opposed to multifunctional formation tester tool that also collects samples. The two important distinctions of this tool are an electromechanically controlled pressure pretest system that enables precise pretest volume and rate. This is in contrast to the hydraulically driven pretest mechanisms in conventional tools. Secondly, because the tool is devoted only to pretesting, it has a very small flowline volume with very tight mechanical construction. The required decompression volume is much smaller than

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conventional tools. The hydraulically controlled single probe module in conventional testers has a 20 cc pretest chamber compared to 35 cc chamber in XPT*. Both tools are capable of taking multiple pretests in one setting.

We also note that the XPT* is a much shorter and a slimmer tool (Ref Table.2 at the end of the paper) compared to

conventional formation testers which makes it more useful in challenging wellbore environment such as slim holes or sticking wellbore conditions. Additionally, the tool has the potential for significant rig time savings as it is easily combinable with Platform Express* and most other open hole wireline services. Finally, the XPT* measurement cycle (from set to retract) can be executed in less than a minute, compared to up to 10 minutes or more for conventional formation testers. This dynamically controlled, intelligent pressure pretest system enables precise control of volume and drawdown rates in a wide range of mobilities. A pressure limit can also be set if desired. When low mobility is anticipated, the pretest volume and rate can be set as low as 0.1cc volume and 2-3 cc/min rates that can help avoid an overshoot below formation pressure, reduce the time required for pressure stabilization during build-up, and ensure accurate pressure measurement. A number of examples can be used to illustrate the benefits of these features in the low mobility formations we have encountered in the Arta fields.

Example 1: Low Pretest Volume As previously indicated, the conventional wireline formation tester had been run to measure formation pressures and to acquire a mobility profile. The Nukhul formations, however, exhibited extremely low mobilities, making formation evaluation challenging and often resulting in dry tests. A formation evaluation campaign using the XPT* was initiated to overcome this challenge. By exploiting XPT* extreme limits of lower volume and rates as compared to conventional formation testers, the operator successfully obtained valid pretest measurements compared to the dry or tight tests by conventional formation testers.

The following section is showing field cases of acquiring formation pressures in low mobility formations. The XPT*

(PressureXpress*) was proposed to overcome conventional formation tester challenges (high drawdown pressure associated with relatively high drawdown volume). A total of nine pressure points were taken with 100% success ratio. Four points that originally resulted in dry tests were repeated with low volume resulting in valid pressure data. Pretests mobilities were in the range of 0.01 to 4 mD/cP.

In Fig. 5 earlier measured Dry or Tight points by conventional parameters were successfully converted to valid pretest of

high and moderate quality by utilizing the PressureXpress* (Fig. 6-7). A usual scattering is observed in pressures acquired in Arta field due to its thinly laminated nature, also observed on the FMI-HD* image; coupled with some supercharging and depletion that add to the scattering effect.

Figure 5: Pressure vs depth plot showing an overview of the tested interval.

Conventional Parameters

XPT* Parameters

Reservoir Response on Pressure Derivative

Dry Test Flowline Storage response

10 ft

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(a) (b) Figure 6: Pressure vs Time plots showing: (a) dry test as a result of taking 5cc pretest volume the typical volume taken with a conventional WFT tool and (b) the same point was repeated with a low 0.15cc pretest volume and resulted in valid repeated pressure point.

(a)

(b)

Figure 7: Pressure vs Time plots showing: (a) dry test as a result of taking 5 cc pretest volume, (b) the same point was repeated with a low, 1 cc pretest volume and resulted in valid repeated pressure point

Delayed formation pressure response, usually concluded as Dry or Tight.

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Pretest Volume = 1 cc Rate = 0.17 cc/sec

Volume = 0.1 cc Rate = 0.04 cc/sec

In Fig. 8, it is observed that in the first pretest excessive pretest volume resulted in undesirable long build-up. At 400 s the engineer retracted the tool, set again, and started taking pretests at small volumes and rates. This process was repeated until build-up demonstrated a response, not until the fifth test. The sixth pretest is performed to confirm the pressure.

Figure 8: Pressure vs Time plots showing tight pretest after taking 1cc volume, it was repeated with two valid pretests of 0.1cc each.

In Fig. 9, we observe that the first and second pretests are valid and repeating when small 3 cc pretest volume is taken. However, when followed the test with a large volume of 30 cc pretest, a dry test resulted.

Figure 9: Pressure vs Time plots showing two repeated valid pretests of 3 cc at 130 s and 180 s. At 420 s a 30 cc test was taken resulted in a dry test Example 2: Heavy Oil Sampling in East Arta Field This section is showing a field case where downhole samples have been collected with MDT* dual packer module in a cased hole environment. An exploratory well in East Arta concession (5 km east of Arta field in Eastern desert) was drilled in September 2011, 5 km east of the main Arta field. The well was drilled with 11.6 ppg water based mud and the primary objective from the formation testing program was to collect a representative formation oil sample.

The open hole logs indicated low permeability in the zone where sampling was planned. Conventional sampling with an MDT* single probe was attempted but was unsuccessful. A huge drawdown pressure was observed due to the high viscosity, heavy oil and low formation permeability. As a result, a non-PVT quality sample was acquired at 124 psi flowing pressure, approx. 450 psi below bubble point pressure. After pumping 41 liters in 4.1 hrs the sample was still 82% water contaminated from the WBM filtrate. DFA results are shown in Fig. 10 and explained in detail in Badry (1994)

1

2

3

4 5 6

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Petrodara then planned an (IPTT) Interval Pressure Transient Test concept utilizing MDT* dual packer option to capture PVT quality sample in the cased hole environment at same depth. Pre job models were prepared to simulate expected

drawdown pressure on multiple permeability scenarios. Based on this it was decided to perforate 1.5 ft of interval using 4 high shot density casing guns.

Job execution involved the MDT* dual packer with a 1 m

spacing (Fig. 11) and an extra high pressure pumpout module. After pumping for 6.6 hrs, PVT samples were collected (Fig. 12). Lab results indicated the bottles contained 94% oil.

Pressure data acquired during sampling indicated sampling pressure was 1580 psi and therefore well above the saturation pressure of the oil.

Conclusion The acquisition of formation pressures using WFT tools can be very problematic in low mobility environments. We have shown through modeling that the key to surmounting these problems is a clear understanding of the effects of pretest volume and flowline decompression on the measurement results. We show field results based on the implementation of our findings and demonstrate that WFT tools with small volumes and low compressibility can achieve superior results in low mobility environments when correct test design procedures are implemented.

Additionally, we show the improvement in sampling success when operations are performed in cased hole environments with dual packer as opposed to operations with a single probe in open hole References Edelman J, Maghrabia K, Semary M, Mathur A, Zaki, A S, Bernechea J M,; 2013; Rod-shaped Proppant Provides Superior

Proppant Flowback Control in the Egyptian Eastern Desert, SPE Middle East Unconventional Gas Conference, Muscat, Oman, 2013

Badry R, Fincher D, Mullins O, Schroeder B, Smits T; 1994; Downhole Optical Analysis of Formation Fluids; Schlumberger

Oilfield Review Volume 6, Number 1 January 1994 Manin Y, Jacobson A and Cordera JR; 2005; A New Generation of Wireline Formation Tester; SPWLA Paper M Presented at

the 25th Annual Logging Symposium, New Orleans Lousiana USA, June 26-29 Moran JH, Finklea EE, 1962 Theoretical Analysis of Pressure Phenomena Associated with the Wireline Formation Tester SPE

Journal of Petroleum Technology, August 1962; SPE 00177

Figure 10: DFA results from probe sampling attempt showing very high filtrate contamination.

Figure 12: DFA result during cased hole sampling, showing clean oil

Figure 11: Schematic of cased hole dual packer

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Weinheber P, Boratko E, Contreiras K, VaDunem F, Spaeth R, Dussan EB, Rueda M Gisolf, A; 2008; Best Practices for Formation Testing in Low Permeability Reservoirs; SPE Paper 115825 presented at SPE Annual Technical Conference and Exhibition held in Denver, Colorado, USA, 2124 September

Table 2: PressureXpress* Tool Specifications