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A Process-Oriented Approach for Assisted-History Matching and Calibrating Comingled production Wells Using Post-Production RFT Data and The Recently Commercialized Optimization Techniques- Ganna Field Case Study
Mira, Ali (Sahara Oil & Gas) | El-Behairy, Amr (Sahara Oil & Gas) | El-Rahman, Mohamed M.Abd (Sahara Oil & Gas) | El-Ghattas, Ahmed (Schlumberger)
Abstract Ganna field is a part of North Bahariya concession which is located in Abu El-Gharadig basin, Western Desert, Egypt. The field was discovered and started production in 2004 through the well Ganna-1 from Middle Abu Roash “G” reservoir. Five main reservoirs were tested and produced during the field life namely Abu Roash “E”, Upper Abu Roash “G”, Middle Abu Roash “G”, Lower Abu Roash “G”, and Upper Bahariya. A 3D reservoir simulation study was performed to aid in field future development. Major challenges appeared during history matching process. The main challenge was the commingled production wells producing from multiple reservoirs with different characteristics. Even most of the static pressure points were measured commingle as well. Post-production RFT data was the key utilized to calibrate the history match and reach the most accurate reservoir characterization for each reservoir individually. The history match strategy depended only on global modifications using the new commercialized optimization techniques. Previously, model calibration or history matching has commonly been conducted on a single deterministic model by “manual” or “Trial and Error” approach. With recent advances in the application of uncertainty and optimization in numerical reservoir simulation it became a must to assess the effect of different parameters not only during history matching but also its effect on the forecast through producing a probabilistic forecasting (3). The feasibility of using the manual history matching with a single deterministic model has become questionable. A Physically-sound proper set of parameters with realistic ranges are introduced at each stage of the process in logical order and introduced to optimizers to get the best history matched case with a possibility of considering more than one history matched case for a probabilistic forecasting scenarios (4). This paper will present the approach utilized for calibrating the comingled production wells throughout post-production RFT data using the new uncertainty & optimization module to obtain the best global matched model.
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Korolev Formation (0.99)
- Africa > Middle East > Egypt > Western Desert > Bahariya Formation > Upper Bahariya Formation (0.94)
- Africa > Middle East > Egypt > Western Desert > Greater Western Dester Basin > Abu Gharadig Basin > North Bahariya Concession > Ganna Field > Abu Roash Formation > Ganna-1 Well (0.89)
Abstract Dragon Oil needed to extend the production lifecycle for it's offshore field wells with lower than expected natural flow regime duration. After reviewing multiple of running the Electrical Submersible Pumping options, Dragon Oil chose to implement tubing conveyed and rigless ESP's to return the candidate wells to the required production levels. This case study highlights the technological rational, challenges in implementing decided strategy and prognosticates expected results & benefits from running the two types of ESP's as an additional well investments. Candidate wells for ESP Artificial Lifting have been drilled from offshore wellhead platforms “1” and “2” into the flanks of the Main Field Reservoirs. Commissioning of the pilot ESP projects is expected by end of 2015.
- North America > United States > Texas > Dawson County (0.34)
- North America > United States > Texas > Yoakum County (0.29)
Multi-Well Correlation to delineate Stacked-Channel Reservoir using High Resolution Micro-imaging Facies
Hassan, Sahar S. (Schlumberger) | Megawer, Abdel Khalek (Qarun Petroleum Company) | Zahran, Hemida (Qarun Petroleum Company) | Emam, Mahmoud (Schlumberger) | Abu El Fotoh, Ahmed M. (Schlumberger) | Haddad, Elia (Schlumberger)
Abstract The Western Desert accounts for approximately two thirds of Egypt's surface area. The region can be divided into a number of large scale structural provinces which developed along lines of weakness in the African basement, in response to lateral movements between Europe and Africa. Seismic evidence has revealed a subsurface comprising a series of low relief horsts and grabens. In places however, the structural history is more complex. The Yusif field located near the Qatara depression, is habituated and, therefore has poor seimic data. Three wells were drilled in the field, Yusif -1X, Yusif-3, and Yusif-4 respectively. The fourth well is planned for the most promising area between the three wells. Formation microimaging was performed in the three wells, and interpretation of the images helped to delineate the sand body propagation and geometry in the field and choose the most promising area for drilling the fourth well. The Lower Abu Roash “G” member usually appears as a fining upward profile from conventional openhole logs. Facies analysis was performed on the “G” member with manual sedimentary dip picking, which revealed the internal structures and directions that can't be observed from conventional logs. Correlation with existing openhole logs showed continuity in the vertical and lateral distribution of the sand body, and queries about the relation between the sand bodies in the three wells arose. The relationship between sand bodies can't be solved by conventional openhole logs correlation. Paleocurrent analysis was performed for the sand bodies in the three wells. The results showed that the main trend of the channel belt propagation is NE. Yusif-3 and Yusif-4 wells were drilled within the channel belt while Yusif-1X location was at the channel margin. Correlation is based on electrofacies, which was extracted from high-resolution formation microimaging in the three wells. It was found that the “G” member top is changed based on high-resolution electrofacies detection, and the fourth well was placed closer to Yusif-3 and Yusif-4 based on the recommendations on the channel activity propagation as identified in the formation microimaging. The sand body thickness in the fourth well was almost double the thickness that was found in the previous three wells.
- Geology > Sedimentary Geology (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.42)
- Geology > Structural Geology > Fault > Dip-Slip Fault > Normal Fault (0.34)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.90)
Abstract Petroleum system modeling has mostly been the preserve of exploration departments in major oil companies, which have the specialist resources to execute these studies. However, as it is a dynamic tool for petroleum system analysis, it also has significant applications in the development stages. It may provide information on several different aspects of the areas surrounding a discovery: show which other closures were located on the same migration pathways from the same source and highlight the likely oil and gas distributions in these closures. show which satellite accumulations were effective traps and their hydrocarbon composition. The chance that the structure has been flushed with another hydrocarbon type, breached and re-charged, or only contains residual hydrocarbon may also be predicted. The compositional information from a 3D petroleum system model can be valuable in: Planning appraisal and satellite exploration drilling, Facilities planning where the hydrocarbon composition and the number of satellites that will contribute to the plateau are important to design vs. economic decisions, and Relinquishment decisions. A discovery well has encountered oil and there is a significant volume of the reservoir updip of the well. 3D petroleum system modeling can be used in determining the possibility of a gas cap and the necessity of the investment in an updip appraisal well. Furthermore with multiple compartments of which only one has been tested the understanding of the effectiveness of the fault seal is critical to determine if the closure may have different hydrocarbon compositions. The 3D petroleum system modeling can prioritize appraisal drilling to test structures that are most likely to have the desired fluid fill. Furthermore in the case of parts of the concession area has to be relinquished the 3D petroleum system modeling can be used to determine which areas has the lowest economical value in the development. The high-resolution charge, thermal and pressure histories are important boundary conditions which are required to understand the genesis of the field and the original properties of the oils, and then to obtain an improved understanding of the conditions under which the development hydrocarbons could have taken place (e.g.biodegradation, multi-phase hydrocarbon filling, thermal maturation, water washing, gravitational segregation, hydrocarbon migration along faults, etc). This provides the best possible definition of the charge, temperature and pressure histories, which will then be available to improve analyses of the genesis and distribution of Hydrocarbons.
Fracturing Fluid Rationalization: First Dual-Viscosity Fracturing Fluid Application in the Middle East
Mira, Ali (Sahara Oil and Gas) | Samir, Mohamed (Sahara Oil and Gas) | Naby, Mohamed Abdel (Sahara Oil and Gas) | Mohamed, Nelly (Schlumberger) | Rojas, Jose (Schlumberger) | Kamar, Ahmed (Schlumberger) | El Sebaee, Mohamed (Schlumberger)
Abstract Dual-viscosity fluid is a fracturing fluid that has been recently introduced to cover a wide range of fracturing applications varying, from a non-delayed to delayed fluid system for treatments in low to moderate to high temperatures, respectively. Reducing the impact of the pressure effect of traditional borate cross-linked systems, the system crosslinker is compact and delivers a relatively high concentration of crosslinker per unit volume; it is also compatible with current metering pumps, covering a range of treatment rates compared to the current fluid system, and this can simplify logistics on location. The North Bahariya oil fields are onshore fields located in the Western Desert of Egypt and operated by Sahara Oil and Gas Company (SOG). The fields contain proven oil reserves in two sandstone packages at relatively shallow drilling depths (6,500 ft. subsea) in the Abu Roash "G" member (A/R G) of Cenomanian (Cretaceous) age. These sandstones comprise the main reservoirs in the field. During the last 4 years, the introduction of various techniques has led to a fourfold increase in the production from these fields. This success story is mainly the result of using the new hydraulic fracturing methods such as channel fracturing technique and continuous improvement of the fracturing treatments. SOG has been at the forefront in applying novel technologies to optimize the fracturing fluid treatment by using the dual-viscosity fracturing fluid to improve the wells potential. This technology has been implemented in Abrar field. As seen in case studies, very positive results have been seen in both zones of the A/R G formation in terms of improvement in the well performance. Experiences in Abrar field illustrate how to optimize the production rate in a marginal field by optimizing the hydraulic fracturing treatment fluid and how to build on this success for subsequent fields while pushing the innovation envelope further.
- Africa > Middle East > Egypt > Western Desert > Greater Western Dester Basin > Abu Gharadig Basin > North Bahariya Concession > Abrar Field > Abu Roash Formation (0.99)
- Africa > Middle East > Egypt > Western Desert > Greater Western Dester Basin > Abu Gharadig Basin > Abu Roash Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.94)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.94)
Integrated Field Management Using Advanced Techniques for Offshore Gas Condensate Field
Fadel, A.. (Abu Qir Petroleum Company) | Safwat, H.. (Abu Qir Petroleum Company) | Dabbour, M.. (Abu Qir Petroleum Company) | Labib, A.. (Abu Qir Petroleum Company) | Belli, A.. (Abu Qir Petroleum Company) | Darwish, H.. (Schlumberger) | Nagy, M.. (Schlumberger)
Abstract Abu Qir Petroleum Company (AQP) is one of the most important gas operators In Egypt. AQP Holds 100% of the exploration, development and production rights of the Abu Qir concession in the Nile Delta offshore. The offshore facilities include six platforms, 34 wells and a network of sea pipelines. Abu Qir Petroleum Company currently is interested in modeling their entire production system from the perforations to the onshore Facility to understand and identify all constraints in the system and the way to improve it. In addition, AQP is interested in identifying any bottlenecks either currently or in the future after adding any platforms or wells according to their intended FDP and to test some operational scenarios like changing terminal pressure, separator pressure, installing compression station, etc. The main objective of this project is to identify any current and future bottlenecks in the production system while honoring operational constraints on wells, production separators, pipelines, and total field gas/liquid processing capacity and identifying any flow assurance issues taking into consideration different field development scenarios for an offshore gas condensate field in the Mediterranean (Abu Qir Field). In many mature gas fields, reservoir pressure decline as a result of gas depletion tends to lead to the onset of liquid loading. Liquid loading in gas wells occur when the gas flow rate falls below a critical rate due to reservoir depletion where the accompanying liquids cannot be lifted to surface. Such liquid accumulations at the wellbore can cause the gas well to cease production eventually. Transient simulation was used to build transient well models that replicate observed field data, and these models are then used to evaluate specific gas well deliquification techniques. This document summarizes the methodology and the results of the complementary work carried out to conduct the project. The document presents the methodology to review, evaluate and optimize the offshore production system from reservoir sand-face up to wellhead starting from data gathering and QC up to estimating the missing reservoir parameters needed for well history matching ending with history matched well models and surface network ready for any optimization if the conditions change.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Abstract Murzuq Basin is an intractratonic sag basin located in the southwestern part of Libya and considered as one of the major profitable basins in North Africa. The basin has been developed during the Late Precambrian-Early Paleozoic time, which went through various reactivated tectonic events. These events were dominant during the Paleozoic era coincided with regional unconformities and major sea level changes that resulted in complex geological configuration of both structural and stratigraphic. Detailed subsurface analysis implemented utilizing seismic and well log dataset of the concession NC186 to evaluate the main Paleozoic tecto-stratigraphic complexities within the northern part of the basin. This analysis guided to understand the major Paleozoic polyphase tectonic evolution in the area of study. Steep reverse basement faults, folds, positive flower structures and paleohighs and paleolows of glacial topography are evidently indication of the observed large-scale tectonic Paleozoic elements. From this study, the basement faults are anticipated to be genetically related to the Pan African Orogeny in origin and played major controller of all Paleozoic events. These faults are striking NW-SE with a vertical throw up to 300 meters and an oblique fault plane. Late Ordovician glacial valleys encountered in the area with more than seven kilometers of wide, which have eroded more than 500 meters of Middle Ordovician and Cambrian deposits. The incised valleys took place along the strike of the major basement faults in the area. The entire large-scale analyzed elements interpreted to be generated, directly and indirectly, by different tectonic regimes (i.e. compressional, extensional, strike-slip and combination) exclusively during Paleozoic time. Therefore, from the detailed interpretation; six phases are introduced as the main representative tectonic episodes of in the northern part of Murzuq Basin. These tectonic phases and episodes have controlled the petroleum system in the basin and the area of study in particular.
- Phanerozoic > Paleozoic > Cambrian (1.00)
- Phanerozoic > Paleozoic > Ordovician > Upper Ordovician (0.69)
- Geology > Structural Geology > Tectonics (1.00)
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- (3 more...)
- Africa > Middle East > Tunisia > Berkine Basin (Trias/Ghadames Basin) (0.99)
- Africa > Middle East > Libya > Wadi al Hayat District > Murzuq Basin > Hawaz Formation (0.99)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Dynamic Temperature Modeling for High Temperature Well Planning
Suryadi, Hendrik (Schlumberger) | Bolchover, Paul (Schlumberger) | Miguel, Dennis (Schlumberger)
Abstract The search for new reserves is pushing drilling into deeper reservoirs where formation temperature becomes a challenge. This becomes significantly challenging with current available drilling tools where the operating temperature can closely reach and at times surpass the downhole tools’ temperature specifications. Service companies are continuously improving technology to increase the temperature limit of the downhole tools to contend with the increasing temperatures; however, the ability to simulate downhole conditions and predict downhole circulating temperatures that the tools will be exposed to continues to be a key factor to successful drilling operations in high-temperature wells. The current well-planning practice of designing high-temperature wells is based on static formation temperature measurement from the offset well and linear interpolation of the formation thermal gradient, which, in many cases, is too conservative, not taking into account various parameters that affect the total energy within the system that leads to the actual temperatures that the downhole tools are physically exposed to. Heat transfer occurs from the formation across the mud and downhole tools. Mud circulation carries mud with heated temperature from the bottom of the hole up to relatively cooler temperature as it approaches the surface, and back down the hole again; this will affect the actual downhole temperature that the tools are exposed to. Energy loss of torque and drag due to contact friction of drillstring with different formation and hydraulic pressure loss can also increase the borehole temperature and downhole tool temperature. A new state-of-the-art dynamic temperature model is required to more precisely predict downhole temperatures and which can be used to guide the downhole tool and services planning, along with operating parameters to be applied. This information is needed to be able to run as many downhole tools and measurements in real time to the tool temperature limit and reduce nonproductive time (NPT) due to pulling out of hole for temperature-related downhole equipment failures. Dynamic temperature modeling takes heat transfer from virgin formation to mud and tool collars into account, while also calculating the effect of circulation, mechanical, and hydraulic friction. The dynamic temperature model can help engineers evaluate expected temperatures for different operations, guiding them to select the appropriate downhole tools for the job. The modeling was used in planning several case study high-temperature wells, and a comparison was done between model results and actual downhole temperature measurements. This new modeling can change the high-temperature well planning perspective on the use of downhole tools in that a higher temperature rating (e.g., above 150°C) is not always required because downhole borehole temperature can be managed by applying the right drilling parameters and correct timing.
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Well Drilling > Drilling Equipment (1.00)
- (2 more...)
Abstract Data collection throughout the exploration stage is of paramount importance, especially for the unconventional projects. Since a vast amount of data is acquired through the well logging, large logging expenditures are usually incurred. In unconventional projects, marginal economics dictate particularly strict budget strategies, including expenditures for logging activities. A significant component of the logging costs is associated with the tool temperature rating. In northern Oman, the bottomhole static temperatures of the tight sandstone gas formation being explored are 175°C [347°F] or higher, which coincides with the upper limit of the conventional logging tools. It has been observed that the tool failure frequency increases dramatically when this limit is approached, leading to repeated logging jobs or regretted (missed) data. The simple way to increase the temperature rating of logging tools to perform at high bottomhole temperatures is to use ceramic electronic boards. However, the cost of this solution is roughly 10 times higher than standard tools. Slightly less costly is acquiring data with logging-while- drilling techniques; this has its own disadvantages, such as logging tool availability and data resolution. Another possible approach is careful assessment of the bottomhole temperature at particular times during logging to enable using conventional tools with lower temperature ratings. The assessment is a challenge itself. Direct measurements are difficult because the temperature gauges on logging tools are affected by heat from the electronic components. It is possible to simulate borehole conditions, but this requires extensive modeling and involves many variables such as cooling from mud circulation; heat transfer among the formation, annulus, and drillpipe; conversion of mechanical energy from drilling to heat; and the addition of hot cuttings to mud. That latter modeling has been performed and verified with the field data in various conditions: vertical and horizontal geometries and different mud types. The study established the achievable bottomhole circulating temperatures at various operations, duration of safe temperature window for less-expensive logging, and the bottomhole temperature profile in various drilling scenarios. This allowed delineating a road map for logging future high-temperature wells in the field.
Impact of Wellbore Orientation on Fracture Initiation Pressure in Maximum Tensile Stress Criterion Model for Tight Gas Field in the Sultanate of Oman
Briner, Andreas (PDO) | Florez, Juan Chavez (PDO) | Nadezhdin, Sergey (Schlumberger) | Gurmen, Nihat (Schlumberger) | Alekseenko, Olga (ICT) | Cherny, Sergey (ICT) | Kuranakov, Dmitry (ICT) | Lapin, Vasily (ICT)
Abstract The goal of the present work is to numerically simulate the effects of wellbore orientation on fracture initiation pressure (FIP). These simulations support the study of FIP sensitivity to arbitrary wellbore position and finding the orientations that correspond to the lowest FIP. A 3D numerical model of the fracture initiation from a perforated wellbore in linear elastic rock is used to model FIP. This model is based on the boundary element method (BEM) and maximum tensile stress (MTS) criterion. The data used were from different zones and blocks of a tight gas-bearing sandstone field in the Sultanate of Oman. The amount and quality of available data allowed comprehensive model development. The model is built for the four blocks of the main field, but can be applied to the other blocks and fields. Since the equations and correlations are not empirical and not field-specific, the model is applicable to a wide range of conditions. Some practical applications of the study include selection of the optimum perforated intervals intended for fracturing stimulation in deviated or almost horizontal wellbores where different parts of lateral sections are not exactly aligned with principal stresses. Drilling wells in a particular direction to the principal stresses for the specific reason to reduce the FIP has not been tested to date and is a subject to further discussion.
- Asia > Middle East > Oman > Fahud Salt Basin (0.99)
- Asia > Kazakhstan > Aktobe Oblast > Precaspian Basin > North Block (0.99)