Compositional gradient is important factor to determined, many signs could lead you. The paper experience some factors in Messla and hence give recommendation.

1. 1 The oil fields middle stage production period S.Khalifa.AGOCo.2018 January
“The Oil Fields Middle Stage Production Period”
S.Khalifa. AGO Co
Abstract.
The most important oilfields production period is the middle stage. Technically, it should be
the most controllable stage as long as reserve depleted economically. Sarir, Messla fields and
its adjacent pools has experienced crude composition gradient signs. The source rocks, and
the fluid characteristic somehow in relevance to CG standard. Yet there are no worldwide
distinct classifications of light oil grades and however the degree of our crude alteration
and/or redistribution? It is too advance and late to evaluate the situation. But maintaining the
reservoir crude viscosity via Gas Oil Ratio regulation possible is very important factor to
maximize reserve recovery. This spectacular where the derive mechanism is a combination of
rocks, oil and water compaction. Otherwise, additional recovery projects would be very
expensive.
Literature review.
[1] Worldwide crude composition defers across geographical regions. No Clear cut on
definition of light crude oil API gravity classification. Variation could occur among
producing countries, every region is in challenge of how to process this nature into a useful
and profitable product. The variation could generate a variation in other reservoir fluid
properties particularly for thick reservoirs or reservoirs with a large structural relief such as
Agoco reservoirs [2]. Variation can be observed in systems in equilibrium when chemical
potential gradients are balanced by gravitational potential gradients [3, 4, 5, 6, 7, and 8] or
where reservoirs have not reached a “stationary state” of zero component mass flux [9]. Fluid
composition variation could affect reserve estimation and recovery factor (Barrufet and
Jaramillo, 2004) and EOR strategies (Riemens and Schulte, 1998; Syahrial, 1999; Hoier and
Whitson, 2001; Luo and Barrufet, 2004; Jessen et al., 2008).
[10] The following studies and research results referenced to CG phenomena.
The degree and time of CG changes depends on a combination of a) multiple source rocks
and b) progressive maturation of a source rock (Gibson et al., 2006) (Hoier and Whitson,
2001). c) Reservoir environment and condition.
The observation remarks CG phenomena ; [11] Asphalting precipitation during migration
may lead to a distribution of varying oil types in the high- and low- permeability layers in a
reservoir and in the lower parts of a reservoir (“tar mats”) [12]. The dynamic flux of an
aquifer passing by and contacting only part of a laterally extensive reservoir may create a
sink for the continuous depletion of lighter components such as methane. Varying
distribution of hydrocarbon types (e.g. paraffin and aromatic) within the heptanes-plus
fractions. Biodegradation varying laterally and with depth may cause significant variation in,
for example, H2S content and API gravity. In regional distances (10-100’s km) the methane
concentrations may lead to neigh boring fields having varying degrees of gas saturation, e.g.
neigh boring fault blocks which vary from saturated gas-oil systems to strongly-under
saturated oils. The gravity segregates “the heaviest components towards the bottom and
lighter components towards the top” [13, 14, 15] and thermal diffusion segregates the lightest
towards higher temperatures and heavier components towards lower temperatures [16] could
be the case. That thermally induced convection creating “mixed” fluid systems with more-or-

2. 2 The oil fields middle stage production period S.Khalifa.AGOCo.2018 January
less constant compositions specifically in very-high permeability or fractured reservoirs [16,
17, and 18].
Fields observation and CG standard comparison.
Initially and/or along the field production life the mentioned reservoirs and pools specifically
Messla and adjacent pools have reported fluctuation on, API grade, down hole static oil
gradient, GOR values, transportation destinations meter reading, and reserve to recovery
expectation.
Typically those reservoirs produces variant of light, sweet crude oil. The API Gravity ranging
between 34-43°. Initially sourced from two crude rocks and connected to the same drainage
and architecture depositional environment. [22,23] Sarir sandstone group is the predominant
alluvial faces type interspersed with minor marine deltaic sequences for almost all reservoirs
and pools. All reservoirs have generated from Sirte Shale Formation, which considered as the
first source potential and Rachmat Formation as the second. [19,20,21] Studies and research’s
indicate that early to mid-mature in the west basin, and middle to late mature in the north
central basin. The differences indicate lateral and vertical variations in kerogen facies input,
as well as changes in the depositional environments in the source rock within the Sirt Basin.
The aromatic hydrocarbon originated from marine to lacustrine shale source rocks, and/or
marine dysoxic to anoxic depositional environment. The oil bearing column is 350 ft average.
Reservoirs and pools location are spaced along 100 km. Their saturation pressure differs from
2600 to 300 psi. All reservoirs derived by a combination compaction of rock, oil, water.
Stress and compaction, water derive are alternative and simultaneous. Generally the reservoir
pressure has declined for about half initial value in all fields.
Initial samples obtains from the top of “tar mat” in Sarir have mean gravity of 24-25 API,
pour point of 55-89 F[Lewis], wax content of 15-24 % asphaltenes content of 14-24%. Pools
like KK, and VV have initially recorded about the same Sarir tar mat. Because petroleum
reservoirs with tar mats often have production de-asphaltation problems associated with
them, reservoir pressure has declined differently in Sarir, and KK pool, VV just opened to
production.
Discussion
• [24]. J. LEWIS says, Sarir complex was discovered before the major advances in
source rock geochemistry that have been made over the past15 years. Few, if any,
studies taken over by the Libyans in 1971, since which time there has been sparse
information available about the field. Definitely Libyan Agoco light crude is
different. In Sarir, Messla reservoirs, and Majed adjacent pools are under saturated
oil reservoirs derived by simultaneous and mutual stress on rocks, oil, and water.

3. 3 The oil fields middle stage production period S.Khalifa.AGOCo.2018 January
MAGID PRODUCTION HISTORY MESSLA PRODUCTION HISTORY( As of Sept, 2017 )
30
C-MAIN FIELD PRODUCTION HISTORY
1966 69 72 75 78 81 84 87 90 93 96 99 02 05 08 11 14 17
0
80000
160000
240000
320000
400000
BOPD(bbl/d)
0.0
0.2
0.4
0.6
0.8
1.0
WC
Date
Random fluid production peaks due to different stress magnitude surrounded reservoirs, indicates different
compaction response w/respect to different fluid composition responses, and reservoir geology structure.
• Worldwide observations reveal that black-oil reservoirs overwhelmingly dominate the
volatile group. The grade referred via initial molecular weight and some of the
physical, intermediate-hydrocarbon components, typically C2 through C7. Table (1)
AA, EE pools and Messla shows different Mw and C7+content.
• Generally phase behavior diagrams and equation of state EOS calculation investigate
CG phenomenon (not available). Hence no distinct definition could be approved. It is
too advance to evaluate the situation and too late to build decisions. The situation
could be relatively referred to unknown CG grade due to volatile oil percentage in
large structural relief [25][26]. But its worth to consider CG concequensses.
Field C1 C2 C3 C7+ R. Temp Mw BPP
EE-Pool 35.48 10.26 8.41 32.33 238 94 2600
AA-Pool 70.2 8.5 5.72 0.81 228 93.3 2450
KK-Pool 31.9 9.06 8.13 35.2 236 101.7 2340
HH-Pool 30.67 9.14 8.64 36.12 228 104 2265
Messla 37.76 15 16.7 7.73 228 125 1348
VV- Pool No data available 250 300

4. 4 The oil fields middle stage production period S.Khalifa.AGOCo.2018 January
• Reservoir viscosity via GOR is the important factor to improve rserve recovery.
Meanwhile to improve the debate between operation dept. and engineering dept. for
the right GOR production value. Average GOR well test report 450 scf/bbl. [27]
Initial Messla PVT recorded GOR 340 scf/bbl as one stage separator, corrected to
468 scf/bbl as three stage separators, error referred wrong experiment type? The
same error for F.V.F encountered. Average GOR at main station just before
transportation fluctuated from 380 on summer to 500 on winter scf/bbl. To determine
the exact natural GOR, five wells selected in Messla field flowed naturally for almost
25 years (the value found =310 scf/bbl).
• As a state-of-the-art surface chokes modeling multiphase flow through chokes is still
under evaluation. The GOR in under saturated reservoirs suppose to be constant.
Hence chock sizes and rates suppose to be linear to each other. By applying the
(critical flow choke equation-Gilbert 1954, Ghareeb et al., 2007) for GOR =350
maximum with respect to 300 psi WHP and different rates (The graphs below show the
required choke sizes for deferent rates).
Recommendation
• It can be agreed that reaching reliable solutions is impossible for many petroleum
engineering problems without precise predicts of PVT properties of petroleum
reservoir fluids (Khoukhi, 2012). It’s imperative to take PVT samples from many
interval depths to sponsor good decisions for new reservoirs discoveries. As well as
operation dept. should anticipate crude changes to upgrade surface facilities
adjustment. It is spectacular to maintain reservoir oil viscosity to GOR = 350 scf/bbl .
Accordingly the optimum choke sizes must be imposed to produce the optimum GOR
values rather than protect Electrical Submersible Pump wells performance. It is
imperative to run a sensitivity analysis for all the available tubing sizes ascertain
which tubing sizes gives 350 GOR productions regarding tubing friction. Reduce
pressure draw down by re-enter wells as short distance horizontal wells oriented
perpendicular to main stress (NE-SW).

5. 5 The oil fields middle stage production period S.Khalifa.AGOCo.2018 January
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