October field is a giant offshore field located in Gulf of Suez (GoS), Red Sea, Egypt. It has around 3 billion STOOIP. October has four main formations; Nubia, Nezzazat, Upper Rudeis and Nukhul. Nubia is the main reservoir since it has around 2 billion STOOIP. Nubia production started in 1979 reaching its peak with 300,000 BOPD. Waterflooding was commenced in 1996. Historically, October Nubia has 100 well penetrations, and currently producing ±10,000 BOPD from active 15 gas-lifted wells what made us very concerned to push reservoir limits to increase production and extend its life. In this paper, there’ll be an elaboration of what was planned and achieved to redevelop & revive October Nubia.
Geologically October Nubia is fluvial layer-cake sandstone with tilted fault block trapping system. It has mainly four productive zones: TZ, MN, M1 and M2 from top to bottom with different qualities ranging from 100 mD in TZ to 2000 mD in M1. It has compositional gradient within 2000 ft. thickness with API range of 22º to 29º. It has weak to moderate aquifer with OOWC at 11670 ft. TVDSS. To revitalize October Nubia, a comprehensive reservoir study was conducted to identify reservoir technical limits, and define possible alternatives in alignment with operational perspective. Almost all reservoir engineering tools were used starting from simple production split, analytical work, kriging simulation, mechanistic modeling reaching to full-field numerical simulation. The study output was very encouraging with massive oil potential. After completing the study, a huge volume of bypassed oil was detected. That bypassed oil was explained by improper historical injectors’ locations especially in presence of high permeable zones.
As a short-term action, a decision was taken to stop injection, which resulted in doubling oil rate due to gradual decrease in WC from average of ± 85% down to ± 60% in many of wells producing the same fluid rate due to constant aquifer support. Another conclusion from the study was increasing offtake from certain wells will not increase WC that’s why gas-lifted wells are being studied to be replaced by ESP, and a third recommendation was to restart Waterflooding by a new pattern & consider polymer flooding to modify mobility ratio, enhance sweeping efficiency and recover bypassed oil volume with a potential of millions of recoverable oil reserve.
Managing giant field is not an easy task. They worth regular studying and evaluation to optimize their development since each 1% increment in their recovery means millions of oil barrels. In this paper, a comprehensive workflow of the study, methodology, and technical tools are illustrated clearly. Ultimately showing how GUPCO managed to extend life of one of its valuable assets.
An increasing number of deviated wells are being drilled to maximize production and hydrocarbon recovery in the mature reservoirs of the Gulf of Suez (GoS). Successfully drilling a high-angle well in a tectonically disturbed and structurally complex area like the GoS is very challenging, especially in depleted reservoirs. Selecting the optimal mud weight is absolutely essential. Stress orientation and magnitude also have a major impact on wellbore stability.
The region poses significant drilling challenges that vary widely from reactive shale and salt creep to stress-related instability. From the findings of multiple wellbore stability projects we conducted in the GoS, we review the dominant mechanisms of wellbore instability in the GoS. We provide a summary of the failure mitigation measures and an overview of stress magnitude and orientation in the region, demonstrating how it impacts the knowledge of the most stable drilling direction.
Understanding the main causes of rock failure in the GoS resulted in improved drilling efficiency and reduced drilling costs. We show an example, where a new, nearly horizontal (86º) well was successfully drilled through the Asl formation with less than half a day of non productive time during the entire drilling process.
We conclude that acquisition of new, high-quality data would considerably reduce the uncertainty surrounding drilling complex wells in the area and reduce their cost.
Bassim, Essam Abdul Elaziz (Arabian Oil Company, Ltd.) | Yamaguchi, Kaoru (Arabian Oil Company, Ltd.) | Juandi, Dedi (Schlumberger Logelco, Inc.) | Emam, Mahmoud (Schlumberger) | Ali, Aziza (Schlumberger Logelco, Inc.)
The carbonate reservoirs in Gulf of Suez area have complex geological structure due to the existence of fractures associated with faults. Thus, fracture characterization of this complicated area is very important to understand the reservoir behavior and hence assigning the best completion intervals for the producing wells.
In this paper, we developed a workflow of integrating formation micro imager, Stoneley waves and petrophysical analysis for better fracture characterization and selecting the best perforation intervals for a producing well. This workflow is applied on well NWO-1, in the Northwest October Concession in the Gulf of Suez area over the carbonate reservoir.
The well was drilled on the peak of anticlinal feature created by fault propagation fold of a normal fault that located nearby the well. The main objective was to determine the structural geology features (i.e. fractures), its orientation and the diagenetic features (i.e. vugs) using formation micro imaging tool. Also, to quantify the effectiveness of fractures as fluid conduit mainly in the carbonate reservoirs either in Thebes or Mokattam Formation via Stoneley waves derived from processing result of sonic measurement. This is combined with the petrophysical interpretation using the elemental spectral device data and other conventional open hole logs to provide a comprehensive petrophysical formation evaluation.
The study reveals that the highest average fracture density is over (Layer-A & B) at the upper most interval of Thebes Formation around 2.2 fractures/ft and (Layer-C) at the bottom around 1.77 fractures/ft. These fractures were proved to be of good fluid conduit based on both Stoneley waves and the petrophysical interpretation. The two layers A and B were recommended to be tested and the DST (Drill Steam Test) results proved the higher productivity than layer C which confirms the outcome from our integrated study.
El-Banbi, Ahmed H. (Schlumberger Data & Consulting Services) | Fathy, Khaled (Schlumberger Data & Consulting Services) | Morsy, Samir Y. (Schlumberger Data & Consulting Services) | Aly, Ahmed M. (Schlumberger Data & Consulting Services) | Alaa, Alam (GPC) | Fattah, Mohamed A. (GPC)
A major integrated study was performed to optimize the development of a complex field and to find opportunities to increase oil production. The field is composed of eight stacked reservoirs. The field was developed with more than 160 wells and has been producing since 1960. A pilot gas injection project was installed in the early 1990's. Despite the large number of wells and long production history, only 10% of the OOIP was recovered to date. An integrated approach was used to construct a dynamic model for the field and couple it to economical calculations. The model was used to optimize the performance of the field, increase recovery factor, and accelerate production. Unique to this paper is the procedure of history matching large amounts of data and long history. A relatively large model was constructed and then was broken down to seven models. The history match was attempted for each model separately. The seven parts of the field were then combined and the history match was refined. This history matching procedure resulted in significant time savings in the study and allowed the study team to dedicate most of their time to field optimization and to understanding the reservoir behavior.
The Bakr-Amer field is one of the General Petroleum Company's (GPC) producing fields in the Gulf of Suez (Fig. 1). It is located in the west-central part of the Gulf of Suez. It is about 10 km to the north of the Ras Gharib oil field and about 40 km to the north of the Ras Shukheir oil field. The Bakr field was discovered in 1958 based on seismic, magnetic, and gravity data. Oil production from the field began in 1960. Amer field was discovered in 1965 and production began shortly after. The Bakr-Amer field is a composite field initially considered as three separate accumulations; namely the South Bakr, North Bakr and Amer oil accumulations. Subsequent work reached a conclusion that the three parts of the field were in fact one continuous reserve. The Bakr-Amer field is 14 km long and represents the central segment of the large NE tilted fault block. It produces oil from several reservoirs made up of reefal limestone, fractured limestone as well as quartzose sandstone (Belayim Nullipore, Lower Miocene limestone, Thebes Formation, Matulla Formation, Wata Formation, Raha Formation, and Nubia Sandstones). Multiple water-oil contacts were identified. The Carboniferous shales of the Nubia-B unit represent the effective seal, which separates the Nubia-CD from shallower reservoirs. The upper horizons (above the -1050 m oil/water contact) are producing from the Lower Miocene, Thebes, Matulla, Wata, Raha, and Nubia-A Formations. On the other hand, the lowest oil pool is producing from the Nubia-CD unit. Fig. 2 shows the historical field oil production. The production of the field during the period 1965 to 1975 came mainly from the Eocene rocks and the recent peak in production from the new developments of the shallowest reservoir (Belayim). Fig. 3 shows the development of water cut over time.
The study reservoir is the Thebes formation of early and middle Eocene age. It was recently discovered in the south Geisum area, Gulf of Suez. The rock formation was deposited in a shallow marine environment and is composed mainly of cherty limestone of complex nature.
In GB-1 well, we have carried out a formation evaluation program to appraise the Thebes discovery using traditional open hole logs in addition to the newly introduced technologies, the Nuclear Magnetic Resonance and the Dipole Sonic measurements.
Eventually, two intervals were perforated and tested. The DST gave a permeability of around 5 md and 70 md for the lower and upper zones respectively. The Magnetic Resonance calculated permeability was around 1 md and 4 md respectively. The produced oil was highly viscous. The Magnetic Resonance was reinterpreted to determine the effect of the highly viscous oil on the permeability calculation.
In field practice, a T2 cut-off of 100 msec is used for carbonate reservoirs. In general, the oil bulk relaxation falls in the free fluid area. However, for 28 cp oil viscosity, the bulk relaxation time for the oil is around 40 to 60 msec. This means that the oil signature is coming inside the bound fluid volume, although it should be free since we assume the rock is water wet.
The oil volume in the invaded zone was deducted from the bound fluid volume and then added to the free fluid volume. The Timur-Coates permeability equation was then used to re-calculate the formation permeability using the adjusted volumes of bound and free fluids, thus resulting in permeability corrected for the viscous oil effects. The re-calculated permeability showed a good match with the permeability obtained from the drill stem test data.
The studied reservoir, Thebes Limestone, occurs within the Geisum field, which is situated in the offshore south-east entrance of the Gulf of Suez (Egypt) at 40 km north of Hurghada City as seen on Fig. 1. The rock formation was deposited in a shallow marine environment and is mainly cherty limestone of complex nature. To appraise the Thebes discovery, a formation evaluation program was performed in well GB-1 using a set of conventional open hole logs in addition to the recently introduced Combinable Magnetic resonance (CMR*). Fig. 2 shows a cross section of the well penetrating the Thebes formation.
Sharag, Mohamed (Geisum Oil Company) | El-Enien, Sarwat Abou (Geisum Oil Company) | Raya, Osama Abou (Geisum Oil Company) | Waheed, Arshad (Halliburton Overseas Ltd.) | Farouk, Ehab (Halliburton Overseas Ltd.)
This case history develops through the drilling of a relatively underexplored and less promising limestone formation in the Gulf of Suez area of Egypt. The target formation, known as Thebes of Eocene Age, was "faulted" and the two separated pay sections presented different rock compositional scenarios. Even though the geological description broadly classified these zones as carbonates, the stimulation treatments designed for the two zones were totally different. The process that was undertaken in determining the best solution was based on the introduction of some novel analytical techniques and a com-prehensive approach to acidizing-treatment design.
This paper details some of the new approaches that were used, including a composite log developed for carbonate-stimulation design. The emphasis on reservoir characterization in terms of its petrophysical properties and production capability is paramount in carbonates because of the extreme reservoir heterogeneity and a general noncorrelation between rock porosity and permeability. Furthermore, a new matrix acidizing simulator was run with input data from the composite log for modeling fluid distribution and skin evolution from the treatment. On the basis of these simulation runs, a couple of preemptive measures were taken to improve the treatment-fluid distribution profile.
Bottomhole pressure gauges in conjunction with real-time monitoring of skin evolution during the treatment were analyzed for determining the effectiveness and applicability of foamed treatments, in-situ crosslinked acid systems, and maximum pressure differential and injection rate (MAPDIR) techniques.
The post-stimulation production results and pressure-buildup surveys confirmed the success and effectiveness of the stimulation treatments.
The Thebes formation is of early Eocene Age in the Zeit Bay field (Fig. 1) of the Gulf of Suez, Egypt. The field is mainly a horst block, bounded to the east and west by two normal faults, further intersected by strike-slip faults. Depending on the location of the well, the Thebes formation can occur at varying depths between 3,500 and 4,400 ft true vertical depth (TVD), or between 3,800 ft and 6,000 ft (MD KB). The formation thickness also varies widely, reaching more than 600 ft in some areas of the field.
Geisum Oil Company first evaluated 1 the Thebes formation in 1998 as a secondary target while it was exploring for oil in the deeper Upper Cretaceous sandstones and fractured granitic Basement. On this exploration well (Well A-8), about 527 ft TVD of pay was encountered that failed to produce in its original completion. Subsequently, a small acid treatment was performed, and a short flow test was conducted on the well. The production estimates were 600 to 700 BOPD of 20° API oil. On the basis of volumetric calculations, the reservoir was estimated to have 5.7 million stock tank barrels (MMSTB) of oil-in-place with possible recoverable reserves of 1.1 MMSTB of oil. A new well (Well B-1) was drilled the following year for evaluating and developing the Thebes reservoir. In drilling and completing this new well, the operator encountered the Thebes formation 450 ft shallower than expected, while the intermediate-hole section of 12¼ in. was being drilled. The drilling prognosis at that stage was that the formation had "faulted," and a repetition of the Thebes existed at a deeper depth ( Fig. 2). The operator confirmed this theory when he encountered the Thebes formation again 440 ft deeper. The two sections were designated as Thebes I (the upper zone) and Thebes II (lower zone) with net pays of 195 ft and 163 ft, respectively.