This study has been undertaken in two oil fields (A-Libya, and B-Libya) in Sirte basin located in Libya. Nubian sandstone Formation is the main reservoir in the studied oil fields. Laboratory resistivity measurements were performed at Libyan Petroleum institute (LPI). The majority of wells, however, are logged and the use of wireline log data in conjunction with some core data has been proposed as a rapid, cheap, and alternative to predict some special core analysis (SCAL) parameters instead of collecting extensive core or performing SCAL measurements in all wells. Neural network predictors are potentially very useful in the present study due to the limited SCAL data for the studied wells. In this work some of SCAL parameters were predicted using neural networks based on different combinations of wireline logs. The procedure firstly involved training the neural network predictors using data in training well A-02. These predictors were then applied to an adjacent well A-01 in the same oil field, and to another test well B-01 in a different oil field. The most frequently used type of neural network is a feed forward neural network using a back-propagation learning algorithm, due to its popularity and simplicity.
Some good neural network SCAL parameter predictors for Rt, and RI were generated using different combinations of standard wireline logs in the training well A-02. The best predictors were produced using the dataset from the entire 478 ft cored interval of the training well and all 7 available wireline logs. Predictors trained on data at 1.0 ft depth spacing appeared to be better in the training well. However, the prediction of resistivity parameters in an adjacent well and a further test well in a different oil field gave slightly better results in general for predictors trained on data at 0.5ft depth spacing rather than at 1.0 ft depth spacing.
Mendez, Freddy E. (Baker Hughes Incorporated) | Siddiqui, Aamir (Baker Hughes Incorporated) | Hanif, Amer (Baker Hughes Incorporated) | Longo, John (Baker Hughes Incorporated) | McGlynn, Ian (Baker Hughes Incorporated) | Gade, Sandeep (Baker Hughes Incorporated) | Blood, David R. (EQT)
Spectral analysis of natural and stimulated gamma rays is a well-established open-hole technology that enables accurate mineral characterization and petrophysical evaluation of conventional and unconventional reservoirs. The determination of detailed mineralogy in the cased-hole environment, however, has been a challenge because of the significantly increased uncertainties caused by the additional attenuation and contribution effects of casing and cement that are observed in the gamma ray spectra. The acquired spectral gamma ray data is processed with proprietary algorithms that are based on a combination of lab experiments and modeled tool response standards. The resulting elemental composition, corrected for the cased-hole environment, is further processed in an expert interpretation system to determine lithology and detailed mineralogy of the target formation. Candidates for this technology include older and newly cased wells where lithology and detailed mineralogy from open-hole logs are not available.
This work discusses some aspects of the corrections needed for an accurate quantification of chemical elements from measurements through casing. The impact of casing collars and presence of cement on the spectral data are also discussed. Finally, we report a case study that uses this technology and illustrates a successful mineral characterization of a complex reservoir rock in the United States. Results show good agreement with an x-ray difraction (XRD) analysis of ditch cuttings. The resulting logs were productively used by the operator to understand the siliciclastic influx as well as the distribution of carbonates in the Big Lime formation. The results also show the ability of the methodology to identify organic carbon directly from measurements of the inelastic spectrum in the cased-hole environment.
The application of pulsed neutron technology (PNT) in cased holes has, so far, been limited to basic lithology identification. This methodology expands the applicability of the PNT, previously mostly confined to open-hole cases, to the cased-hole environment and enables operators to take full advantage of the valuable information contained in high-resolution inelastic, capture and natural spectra. This enables characterization of hydrocarbon-bearing formations to a level of detail previously possible only from open-hole data.
Pressure transient well test analysis is commonly used to help characterize oil and gas reservoirs. In a typical well test, interpretation of rate/pressure data usually yield information about permeability, skin factor, boundary conditions, and character of the reservoir. Some well tests, however, suffer from ambiguity and non-unique interpretation. The objective of this study is to apply the Artificial Neural Network (ANN) technology to identify the reservoir model. A multilayer neural network, with back propagation optimization algorithm, is used to identify the reservoir model. The required training and test datasets were generated by using the analytical solutions of commonly used reservoir models. Nine ANN networks were constructed with each one capable of differentiating among six boundary models. Most commonly found reservoir models of different inner, outer boundary and reservoir medium are included (e.g. vertical, fractured and horizontal wells; homogenous, dual porosity and radial composite reservoirs; and infinite, one sealing fault, two sealing faults, rectangle and circle boundaries).
Each of the ANN of the nine networks has been constructed by one input layer, two hidden layers; and one output layer with six nodes characterizing the different reservoir boundary models. Different network structures and training intensity were tested during this work to arrive at optimum network design.
The performance of the proposed ANN was tested against simulated noisy and smooth datasets. The results indicate that the proposed multilayer neural network can recognize the reservoir models with acceptable accuracy even with complex models. The comprehensive testing of different ANN designs showed that success rate increases significantly by distributing the commonly used reservoir models into nine networks. This ANN design can still yield good results even with some noise in the pressure data. After testing the ANN, they were then used in the interpretation of several field cases (including complex tests) and results are presented in the paper.
This paper describes case-studies of Formation Isolation Valve design, completion options, installations, well bore access for Intelligent Completions and successful replacement of electrical submersible pump (ESP). These completions are installed for production optimization in multilateral and horizontal wells. ESP completions has a long history in oil field and intelligent completions have been nearly stared 15years back.
Isolation Valves have been installing for over 20 years and more than 2000 wells have been successfully completed. In few wells upper completions have been successfully recompleted with ESP. The technology has provided real value in these ESP wells and also in intelligent completions wells.
There are several measures such replacement of underperforming ESP systems, sidetracks in more prolific zones and upsizing of the pumps have been taken. The formation isolation valves were used with ESP completion to protect reservoir formation from drilling and work over fluids during replacement of pump. This saves fluid cost, rig time, reduce rig cost, avoid formation damage and improve productivity. Few benefits are below: Allows multiple pump replacements without killing the well Isolates formations without applying kill fluid to the formation Reduces fluid losses during completion installations Improves well productivity by preventing formation damage Reduces costs associated with well interventions
Allows multiple pump replacements without killing the well
Isolates formations without applying kill fluid to the formation
Reduces fluid losses during completion installations
Improves well productivity by preventing formation damage
Reduces costs associated with well interventions
ESP systems with formation isolation valve are delivering the industry the solution to achieve production targets while protecting reservoir damage due to kill fluid during work over operations for pump replacement and at the same time allowing access to mother bore for stimulation and logging in ESP and Intelligent Completions.
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.
Thanks to its relatively friendly impact on the environment, natural gas usage has evolved to the point that puts forward natural gas as one of the main energy sources worldwide. Aside from the fact that natural gas is widely spreading all over the world and that securing natural gas supply has become a matter of great concern to all energy market players, natural gas still suffers from significant price variations and long-term supply dependency, which results in limited competition, less flexibility and reduced diversity of supply.
In particularly compared to liquid fuels, natural gas lacks certain features required for commoditization. These features are found in the so called "perfect competition" market structure and include among others, standardization or inconsiderable differentiation of the sold product, neglected price margin, diversity of supply, increased cost and hence price stability, availability, and obtainability. In general, product commoditization shall result in a number of benefits not only for the end users, but as well for all involved players along the whole processing value chain.
The aim of this paper is to investigate whether or not natural gas can be classified as a commodity and the forces that are currently affecting this commoditization process.
In doing that the paper will study the effect of natural gas transportation infrastructure costs, long term versus spot market contracts, storage methodologies, LNG compared to natural gas from a commoditization perspective and security of supply requirements. The paper will also discuss the reasons for the increased natural gas price differences worldwide. Finally, it will highlight some of the existing eco-political forces that might affect the pace of natural gas commoditization taking into account the effect of subsidy and trade barriers in certain regional markets on the commoditization process.
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.
Forno, Luca Dal (eni Algeria) | Latronico, Roberto (eni Algeria) | Saldungaray, Pedro (CARBO Ceramics) | Petteruti, Ernesto (eni Algeria) | Fragola, Daniele (eni Algeria) | Allal, Mohammed A. (Sonatrach) | Hachelaf, Houari (Sonatrach) | Albani, Danilo (eni Algeria) | Hamdane, Toufik (Sonatrach) | Carpineta, Gabriele (eni S.p.A)
Bir Rebaa Nord (BRN) and Bir Sif Fatima (BSF) fields, operated by Groupement Sonatrach-Agip (GSA, a JV between ENI and Sonatrach), are located in the Berkine basin in north-eastern Algeria. These fields are characterized by oil-bearing sandstone reservoirs with low to medium petro-physical properties. During the development phase, to counteract the effect of pressure depletion, water and gas injection was implemented for reservoir pressure maintenance. In addition, due to the increasing water cut, artificial lift systems were employed to effectively produce these fields.
Hydraulic fracturing has been implemented in GSA since year 2000 to improve well performance, both in terms of productivity and injectivity for oil producers and water injectors respectively. The fracturing process has been improved over the years regarding operational procedures, enhanced reservoir knowledge and implementation of new technologies towards resolving the many uncovered challenges. Changes to the perforation strategy, fracturing fluids formulation, rock mechanics studies and design of proppant schedules are examples of enhancement to the fracturing practice that have been implemented in the recent years.
One of the uncharted matters in GSA, coming out from the post-job data re-processing, was the necessity of a precise characterization of the hydraulic fractures vertical coverage. The presence of several sandstone layers with different properties brought questions if the fracture had grown into an unwanted zone or may had not properly covered the entire target formation. Moreover, fracture height is an essential parameter for frac models calibration. Its accurate determination drastically reduces the margin of error in treatment net pressure matching, helping to more precisely established fracture half-length and width, stress profile and, last but not least, achieving a calibrated model for future operations in the same area.
This paper describes the successful implementation on two water injector wells of a novel non-radioactive detectable proppant for the first time in Algeria. The taggant material within the proppant has been located by comparing the pulsed neutron capture cased-hole logging passes registered before and after the hydraulic fracturing treatments. The detectable compound does not affect proppant properties and, in addition, its non-radioactive nature reduces the timing for materials delivery and eliminates the HSE risks linked to other tracing methods.
The pulsed neutron measurements evaluation provided valuable information regarding fractures confinement, avoidance of contact with undesired layers and possible presence of cement channeling. Furthermore, combined with sonic logs and cores data, it helped refining the geo-mechanical model for future interventions design in the same reservoirs.
This paper presents an optimization analysis of different development options of Nahr Umr reservoir in Subba oilfield. Nahr Umr reservoir is a highly heterogeneous clastic reservoir with moderate edge a bottom waterdrive and it has a short production history for six months. Many different development scenarios have been conducted in this study to test possible predictive scenarios to determine the most significant development option. The black oil commercial software simulator, Eclipse-100 was used to study fluid flow in the reservoir and to predict the future behavior of reservoir. The prediction scenarios considered in this study include, natural depletion through the existing wells, determine the optimal number of infill producers, and waterflooding option through conducting peripheral and five-spot patterns. The development plan assumed to commence at January 2017, then couple of runs using simulator flow model were conducted for ten years. The waterflood sceneries startedup on January 2023 and January 2027 for inverted five-spot and peripheral patterns respectively with 58 producers and 66 injectors for peripheral pattern and 102 producers and 77 injectors for inverted five-spot pattern. The results are analyzed based on economic criteria to optimize the number of infill drilling. The optimization of development options was achieved based on net present values analysis.
Xu, Jianchun (China University of Petroleum (East China)) | Han, Guangwei (China University of Petroleum (East China)) | Jiang, Ruizhong (China University of Petroleum (East China)) | Deng, Qi (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Zhao, Yulong (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
In this paper, a new mathematical model of multistage fractured horizontal well (MsFHW) considering stimulated reservoir volume (SRV) was proposed for tight oil reservoir considering different regions and formation properties. In this model, two regions with different formation parameters were distinguished. Non-steady state flow in matrix was considered which is reasonable for tight oil/gas formations. The SRV is characterized by the inner region. Both inner and outer regions were assumed as dual porosity medium. Then, the solution of multistage fractured horizontal well performance analysis model is obtained by the point source function method and the source function superposition principle. The pressure transient analysis (PTA) for well producing at a constant production rate was obtained and discussed. At last, different flow regimes were divided based on PTA curves. The effects of related parameters such as SRV radius, inner-porosity coefficient, mobility ratio, fracture number, fracture half-length and fracture spacing were analyzed.