Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
Kortam, Mostafa Mahmoud (Petrobel) | Siso, Samir (Petrobel) | Abbas, Nelly Mohamed (Schlumberger Egypt) | Salah, Ahmed (Petrobel) | Hesam, Atef (Petrobel) | Cilli, Andrea (Petrobel) | Kamar, Ahmad (Schlumberger Egypt) | Khafagy, Fatmaelzahraa (Schlumberger Egypt)
The development of low quality reservoirs such as; low permeability, marginal assets, and unconventional resources has a several cost challenges pushing the industry toward maximizing the potentiality and optimizing the strategies of such high risk plays.
Petrobel has a discovered one of such challenged asset and successfully conducted a comprehensive study to set the best development strategy to unleash this potential. SIDRI Area is a relatively new settlement with a reasonable hydrocarbon potential according to petrophysical analysis. The target formation of SIDRI wells is a sedimentary rock with granitic facies that consist of a series of tight conglomerates over an oil/water column of more than 900m. The pore system of this rigid and stiff formation consists of a micro natural fractures network with secondary cemented porosity. The production is mainly governed these tiny natural fractures that have a permeability as low as 0.1-0.5 md. Despite this tightness these series are separated by nonporous sections that occasionally exhibit as barrier and may introduce layering or subdivision of pay, however in sometimes permit a vertical communication between productive sections. Performed Cuttings analysis such as XRD, thin-sections showed a variety of minerals composition representing different lithology which in turn complicates the characterization of such reservoir.
On top of the unique mineralogy, the executions of fracturing treatment of SIDRI wells include multiple other challenges. The higher reservoir temperature and the formation depth cause a great constraint in terms of pumping rate and pressure. Besides, the non-availability of pumping equipment of high Horsepower restricts the pump rates and also limits the utilization of slick water frac. Even the nature and the quality of crude oil is quite challenged since it is a heavy black oil type and its composition contains high number of asphaltenic compounds accordingly the opportunity of creating sludge with treatment fluids is highly likely. The oil water viscosity ratio at reservoir condition represents a weighted obstacle for oil recovery that should be overcome.
The basic concept of applying hydraulic fracturing for these kinds of reservoirs is very simple, however the execution to get much more production improvement is quite difficult. Particularly the main idea here is to conduct a cost effective fracturing treatment with economical wisdom principle that can lead to achieve a greater oil recovery with best profitable model.
GUPCO is one of the largest E&P Companies in Egypt and Middle East. It has a vast infrastructure with a large number of wells, platforms, pipelines and offshore facilities. GUPCO's peak production exceeded 600,000 BOPD in 1983 while it produces around 100,000 BOEPD today from more than ten geological formations in Gulf of Suez (GoS). GUPCO produced more than 4.6 billion STBO which represent more than 43% of Egypt's total cumulative oil to date. And in spite of that, we still have many opportunities and success yet to achieve.
As one of the petroleum industry leaders, GUPCO was and will always seek success and excellence in managing its assets. For more than fifty years, GUPCO used to follow the highest standards available in petroleum industry, and applied them in all areas to achieve that outstanding excellence. From day one, GUPCO realized that understanding subsurface features and optimizing recovery from different fields are the key areas among all. As a result, GUPCO had made concerted efforts in those areas in specific.
Managing giant fields is not an easy task; it requires special knowledge and experience to manage such critical asset since each 1% increment of oil recovery means tens of millions of oil barrels. And because GUPCO has four giant fields, it was serious for us to do our best to maximize their value. GUPCO started that early whilst exploration phase, appraisal, development and currently in maturity phase. Along these different phases, we utilized wide spectrum of tools starting from basic technical elements (e.g. flow equations, DCA, MBE, PTA… etc.) reaching to state-of-the-art techniques and technology available (e.g. Numerical Modeling, Artificial Intelligence and EOR) at which GUPCO uses numerical reservoir simulation extensively, utilizes neural network in different applications, and already applied TAP (Thermally-Activated Particles) technique which is called commercially BrightWater® to improve sweeping efficiency, and also studied feasibility of Low Salinity Waterflooding (LoSalTM) which is planned to be implemented in near future after upgrading water injection facilities.
In this paper, we are going to present various case studies with detailed elements GUPCO followed to accomplish that success in managing giant fields, and how such powerful techniques contributed in maximizing our asset value. We'll explain also what we did from day one highlighting different challenges we faced and how we managed to solve them, and more importantly, we'll elaborate our experience in dealing with giant fields under all levels of field's maturity, highlighting the importance of many tools we've utilized. And ultimately, proposing guidelines to be followed whilst applying Waterflooding for utmost benefit.
Fahmi, Adel (Belayim Petroleum Company) | Attia, Alaa (Belayim Petroleum Company) | El-Tokhy, Medhat (Belayim Petroleum Company) | Saber, Sharif (Belayim Petroleum Company) | Madkour, Alaa (Belayim Petroleum Company)
The present work is intended to summarize some observations derived from the structural seismic interpretation carried out in Abu Rudeis/ Sidri field, based on the recently acquired OBC-2010. A new 3D OBC Seismic survey was acquired recently in the area in 2010 Showing a new and more interesting exploratory blocks in the Miocene (Nukhul Fm) and Pre-Miocene (Lower Senonian, Turonian, Cenomanian and Nubia sandstone) in addition to, the new un-conventional reservoir (fractured Igneous intrusions and meta sediments).
The study area is located within the north western of Red Sea- Gulf of Suez. The rift system is interpreted started around the late Oligocene and continue throughout the Miocene, and undertook extension in N650 W direction, nearly perpendicular to pre-existing WNW trending pan African shear Zone fabrics in the crystalline basement of the Sinai African plate.
The interpreted fault pattern is characterized by a series that comprises two sets of faults. The first corresponds to the northwest-southeast trend, which bound the study area from the South, offset fault segments throughout ramp relay structures, with maximum throws around 1000 m, juxtaposing Eocene-Paleocene sediments from the down-thrown block (basin wards) against the basement in the up-thrown block, the second system trends northeast-southwest and is interpreted as a later evolution of the rifting this last mainly strike slip and, the pre-existent northwest-southeast trending off-set fault segments by breaking the ramp relay structures.
As a fruitful result of the new 3D-OBC seismic survey, a positive result of the drilling good discovery proved the presence of the hydrocarbon potentialities and proved the conventional and unconventional reservoir.
The summary of these observations regarding the tectono-stratigraphic evolution of Abu Rudeis field area advocates both, remaining field exploration and development opportunities.
GUPCO (Gulf of Suez Petroleum Company) is the pioneer in Egypt and Middle East in applying conventional waterflooding projects fas a secondary recovery method, Starting from Morgan field, Ramadan, October and July field by injecting into different reservoirs such as Lower Rudies, Upper Rudies and Cretaceous. These successful examples have been done and still running to recover greater amount of oil utilizing more advanced techniques like BrightWater and LoSal. The Heavy oil block in July field which is located in the Gulf of Suez (GoS) was discovered in Jan. 1986 by appraisal well J53. Many tests were performed to get the extension, characteristics of the reservoir and the hydrocarbons as well. It was found that the API gravity of oil is 19 degree. Using Numerical Simulation, we could define different scenarios of depletion plans to maximize the recoverable oil, and hence a decision was taken to start and implement the optimum scenario. This paper will discuss different scenarios and the selected optimum depletion plan, and comparing between the forecast from the model versus the actual achievement addressing production performance, reservoir rock characteristics, Data gathered and surveillance plan for the reservoir since May 1996 followed by water injection using dual string completion in December 1996. The paper is a good example as a case study for the value of using the technology of 3D modeling to maximize the recovery from challenging reservoir like heavy oil reservoirs in addition to proving that waterflooding has successfully improved the recovery of 19 API degree oil in July field.
An integrated reservoir study was initiated to look for new opportunities in East Zeit field. The working team managed to construct the full field static and dynamic models. The main challenge during the history match phase was the high complexity of the structure, range of uncertainties, and the model running time. The team managed to understand unconventional reservoir aspects such as:
(1) The reservoir pressure was sharply decreases as production increases. Then, when the reservoir was abandoned as a depletion drive reservoir the pressure started to increase up to initial reservoir pressure without any intervention.
(2) The performance of few wells completed in the above mentioned reservoir was similar to the performance of wells in active water drive reservoirs.
Comprehensive work in the history match has been done to calibrate the model and explain the different phenomena in the field. The team explained the pressure increase in the depleted reservoir that it was due to the reactivation of faults which became non-sealing. This resulted in communication with another active water drive reservoir and natural miscibility process. The study recommended adding new off take point in the reservoir to confirm the concept. So, a new well was drilled and confirmed the study conclusion and managed to add more reserves and production in the rejuvenated reservoir after 12 years of shut in. Currently, constructing complete field development plan is in progress to maximize the recovery factor. Reservoir monitoring even after abandonment, especially with unconventional reservoir aspects, is very important to discover new opportunities and maximize the recovery. These opportunities should be managed through the integrated reservoir simulation studies to minimize the risk and cover the uncertainties.
The East Zeit field (EZ) is situated in the southern Gulf of Suez (GoS) in about 240 ft of water (Fig.1). The oil accumulation in the field covers an approximately 27 km2 area. The field is composed laterally of two major fault blocks; the main fault block (MFB) and the east fault block (EFB). Moreover, each major fault block is sub-divided into smaller fault blocks which reflect the complexity of the highly faulted structure. Each major fault block is sub-divided vertically into three main reservoirs (Fig.2). The field was started production in 1985 through two platforms; the wells were flowing naturally in the past and currently some wells are producing by artificial lift and other wells are still flowing naturally.
Metwally, Ahmed Sabaa (Agiba Petroleum Co.) | Abd Raboh, Tamer Abdel Nabi (Agiba Petroleum Co.) | Crema, Giordano (Nigerian Agip Oil Company Ltd NAOC) | Itoua-Konga, Felix (Agiba Petroleum Co.) | Bekhiet, Abdallah (Agiba Petroleum Co.) | Salvini, Giovanni (Eni) | El Farahaty, Mostafa Mohamed (Agiba Petroleum Co.)