Complex hydrocarbon distributions where reservoirs are filled by oil and gas phases with different densities and genetic types interfingering within a basin are a common phenomenon in Southeast Asia and are often attributed to vertical migration. Attempts to understanding the controlling factors of vertical hydrocarbon migration by modeling the hydrocarbon charging and entrapment history from two Cenozoic basins in Southeast Asia—West Java and the Madura Platform—are discussed.
A modified invasion percolation algorithm was used to simulate the secondary migration models, which follows the principle that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy and capillary forces. Three-dimensional (3D) seismic data were used as the base grid for migration simulation to capture the effect of both structure and facies variations on fluid flow.
Two models, one from the West Java Basin (fault-bounded structure) and the East Java Basin (nonfault-bounded structure), are presented. For both cases, interfingering between oil and gas occurred, with most oils trapped within the lower formations, a mixture of oil and gas dominates the middle formations, and mostly gas in the upper formation. These vertical arrangements are possible because of the relatively weak formational seals within the basin. For vertically distributed reservoirs, oil is often trapped within the lower interval, and gas is trapped at the upper interval. For a basin dominated by a vertical migration regime, the potential risk for hydrocarbon lateral travel far away from the kitchen is high, thus increasing the potential risk of prospectivity away from the kitchen. Understanding factors that help control vertical migration also help geologists better understand hydrocarbon distributions within the basins.
Case studies during which modeling helped determine the factors that influenced vertical hydrocarbon migration and the resulting potential phase distribution prospectivity risks in the studied basins are discussed.
Cai, Zhenzhong (Tarim Oilfield Company, PetroChina) | Zhang, Hui (Tarim Oilfield Company, PetroChina) | Yuan, Fang (Tarim Oilfield Company, PetroChina) | Yin, Guoqing (Tarim Oilfield Company, PetroChina) | Wang, Haiying (Tarim Oilfield Company, PetroChina)
The Kuqa depression located in northern Tarim Basin is the second largest natural-gas field in China, however, drilling engineering is faced with extremely complex geological conditions, such as complex structural movement history, complex formation conditions (huge thick gypsum salt rock, and different thickness of alternating sand/shale sequences and conglomerate), abnormal high pore pressure systems and strong anisotropy in situ stress. These complex geologic conditions result in severe wellbore instability problems.
An integrated research was conducted combining geology, geomechanics and drilling engineering to solve drilling problems caused by complex geological conditions. Firstly, geomechanical models are established according to the geological characteristics of different formations to get orientation and magnitude of stress, pore pressure and rock mechanical parameters. Secondly, based on rock mechanics experiments and wellbore information, the geomechanical mechanism research of wellbore instability was carried out under complex geologic conditions. Finally, the geomechanical model, wellbore stability parameters and the mechanism of drilling problems are applied to the drilling engineering design optimizing mud parameters, wellbore structures and trajectory of high deviation wellbore.
It is shown that geomechanical approach can improve wellbore stability and drilling rate. (1) For the uppermost conglomerate formation, according to the experimental study of the failure mechanism of conglomerate, accurate mud density is the key avoiding causing extension fracture around conglomerate grains. (2) The mechanical stability of borehole in alternating sand/shale sequences is good, but it is easily affected by hydration. Therefore, high quality mud properties can be matched with low mud density to maintain wellbore stability and improve drilling rate. (3)The interior of gypsum-salt sequences is divided into six lithologic sections. Based on the detailed analysis of different lithology, an in-situ stress model is established optimizing the mud density to find a balance between creep resistance and preventing from lost circulation. (4)Pay zone belongs to fractured sandstone under strong stress background. It shows strong anisotropy in stress field and rock strength. The mud density window determined by this mechanism can not only maintain wellbore stability and prevent lost circulation, but also protect reservoir.(5)The feasibility of highly deviated well was demonstrated based on geomechanical approach. And the wellbore trajectory was optimized in four aspects: avoiding shallow fracture, maintaining wellbore stability, traversing more effective fractures, and easy fracturing after drilling.
Geomechanical research under complex geologic conditions promoted the recognition of the mechanism of wellbore instability, and optimized the program of drilling engineering. The drilling incidents of formation above salt were reduced by 50% and the non-productive time was reduced by more than 20%. At the same time, this research project also promotes the successful implementation of the first highly deviated wells which provided a new way to further improve the gas productivity in this area.
The artificial lift system (AL) is the most efficient production technique in optimizing production from unconventional horizontal oil and gas wells. Nonetheless, due to declining reservoir pressure during the production life of a well, artificial lifting of oil and gas remains a critical issue. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift in tight formations, there remains differing assessments of the best approach, AL type, optimum time and conditions to install artificial lift during the life of a well. This report presents a comprehensive review of artificial lift systems application with specific focus on tight oil and gas formations across the world. The review focuses on thirty-three (33) successful and unsuccessful fieldtests in unconventional horizontal wells over the past few decades. The purpose is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed.
This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
This challenging reservoir characterization case study is defined by the interaction between two reservoirs with different production mechanisms: a fractured basement reservoir and an overlying sandstone reservoir. The existing static geologic concept has been significantly enhanced by integrating pressure data from a unique three-year shut-in period to aid modeling of fractured reservoir connectivity. Previously, the seismic dataset was predominantly used to model the fault and fracture network and guide well planning. In the current approach, the full field data set, including all drilling parameters and new reservoir surveillance data were integrated to address uncertainty in the connected hydrocarbon volume and the relative importance of each production mechanism. The result is a reservoir management tool with which to test re-development concepts and effectively manage pressure decline and increasing gas/oil ratio (GOR) and water production.
To achieve a fully integrated history matched model, the first step was to make a thorough review of the existing detailed seismic interpretation, vintage production logging tool runs (PLT's), wireline logs (including borehole image logs (BHI)) and drilling data to find a causal link between hydraulically conductive fractures and well production behavior. In parallel, a material balance exercise was run to incorporate the new pressure data acquired during the field's shut-in period. The results of the material balance analysis were combined with seismic and well data to define the distribution of connected fractures across the field. Additionally, the material balance analysis was used to determine the connected hydrocarbon volume, the distribution of initial oil in-place and the relative hydrocarbon contribution from each production mechanism.
The field is covered by multi-azimuth 3D seismic and 43 vertical to highly deviated development wells, providing significant static and dynamic data for characterizing the distribution of connected fractures. Despite this high quality, diverse and field-wide dataset, prior modeling iterations struggled to sufficiently describe the production behavior seen at the well level. This has resulted in a major challenge to predicting the production behavior of new development wells and planning for reservoir management challenges. Capturing the complex interaction between production variables (including lithology, matrix versus fracture network, geomechanical stresses, reservoir damage and pressure depletion) at a field level instead of at an individual well level resulted in a unified static and dynamic model that reconciles all scales of observation.
This oilfield represents a unique reservoir characterization opportunity. The result is a key example of how iterative, integrated geological and engineering driven reservoir modeling can be used to inform the development in a complex, mature field. This case study provides an excellent analogue for the reservoir characterization of other fractured Basement fields and/or Basement-cover reservoir couplet fields in the early to late phases of their development.
PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.
A hydrocarbon find has always been an exploration geologist’s adventure and has remained at the forefront of the E&P cycle for the survival of the oil and gas industry. Big and easy finds are a distant past; therefore, the quest has shifted to go beyond conventional sandstones and carbonates to more complex areas of unconventionals: low porosity, low permeability, low resistivity, tight and ultra-tight, HPHT, shale, CBM, gas hydrates, and any other possible regime including deeper, geologically complex, and seismically opaque features such as salt, basalt, sub-basalt, even basement.
Africa (Sub-Sahara) Eni started production from the Nené Marine field, which sits in the Marine XII block in 28 m of water, 17 km offshore the Republic of the Congo. The first phase of the field produces from the Djeno pre-salt formation, 2.5 km below the ocean floor at a rate of 7,500 BOEPD. Future development will take place in several stages and will involve the installation of more production platforms and the drilling of at least 30 wells. Eni (65%) is the operator with partners New Age (25%), and Société Nationale des Pétroles du Congo (10%). The well's primary target is the Bunian structure: a four-way, fault-bounded anticline, which was defined by a 3D seismic survey. It will be drilled to a total depth of 1682 m.
Africa (Sub-Sahara) Bowleven's Moambe exploration well on the Bomono Permit onshore Cameroon has encountered hydrocarbons. The well was drilled to a planned total depth of 5,803 ft and made its discovery in Paleocene-aged (Tertiary) target reservoir intervals. Moambe is the second in a two-well exploration program on the permit. The first well, Zingana, also discovered hydrocarbons. The Moambe well will be tested before further testing takes place at Zingana. Bowleven holds 100% interest in the permit. Shell Nigeria Exploration and Production has begun production at the Bonga Phase 3 project, an expansion of the deepwater Bonga project in Nigeria. Peak production from the expansion is expected to be 50,000 BOEPD, which will be shipped by pipelines to the Bonga floating production, storage, and offloading facility.
Cold heavy oil production with sand (CHOPS) involves the deliberate initiation of sand influx during the completion procedure, maintenance of sand influx during the productive life of the well, and implementation of methods to separate the sand from the oil for disposal. No sand exclusion devices (screens, liners, gravel packs, etc.) are used. The sand is produced along with oil, water, and gas and separated from the oil before upgrading to a synthetic crude. To date, deliberate massive sand influx has been used only in unconsolidated sandstone (UCSS) reservoirs (φ 30%) containing viscous oil (μ 500 cp). It has been used almost exclusively in the Canadian heavy-oil belt and in shallow ( 800 m), low-production-rate wells (up to 100 to 125 m3/d).