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.
Dutta, Sandipan (Cairn Oil & Gas, Vedanta Ltd.) | Kuila, Utpalendu (Cairn Oil & Gas, Vedanta Ltd.) | Naidu, Bodapati (Cairn Oil & Gas, Vedanta Ltd.) | Yadav, Raj (Cairn Oil & Gas, Vedanta Ltd.) | Dolson, John (DSP Geosciences and Associates LLC) | Mandal, Arpita (Cairn Oil & Gas, Vedanta Ltd.) | Dasgupta, Soumen (Cairn Oil & Gas, Vedanta Ltd.) | Mishra, Premanand (Cairn Oil & Gas, Vedanta Ltd.) | Mohapatra, Pinakadhar (Cairn Oil & Gas, Vedanta Ltd.)
The Eocene Lower Barmer Hill (LBH) Formation is the major regional source rock in the Barmer Basin rift, located in Rajasthan, India, and has substantial unconventional shale potential. The basin is almost completely covered with 3D seismic, providing an opportunity for more surgical mapping of the rapid structural and stratigraphic changes typical with any syn-rift deposit. Thick sections of organic-rich black shales reaching 400 meters thickness with TOC up to 14 wt. %, were deposited during a period of widespread basin deepening. Algal-rich type I oil prone kerogens dominate in north and generate oil, with very little gas. These shales mature at much lower temperatures than the mixed type I and III kerogens in the south, which also generate much larger amounts of gas and oil, and at higher threshold temperatures. The variable kinetics, as well as rapid facies variations typical of rifts, provide challenges to high-grading and testing unconventional shale plays.
Extensive Rock Eval pyrolysis and source rock kinetic databases were combined with petrophysical analysis to determine log-based porosity and saturations and productive potential. Modified Passey techniques calibrated to NMR log porosities provide estimates of organic richness as well as maturity and shale oil saturation. Basin modeling using Trinity software provides probabilistic ranges of generated and expelled hydrocarbons to determine storage capacity. The modeled oil window storage capacity varies between 6 to 13 MMBOE/km2, comparable to the values observed in Eagle Ford and Barnett Shale plays, but in a rifted basin and not broad cratonic shelf deposits.
Excess pore pressure was modeled using the kinetics of kerogen-to-oil conversion, and is noted in some of the deeper wells in tight sandstones, but not confirmed in the undrilled grabens. These pressure-gradient maps, along with oil properties (viscosity and oil mass fractions) derived from the geochemical model, are used to compute the producibility index. Composited storage capacity and producibility index maps have high-graded potential pilot areas.
In contrast to cratonic shale plays such as the Bakken or Eagle Ford, rapid and substantial facies variations occur due to local input of clastics and variable turbidite geometries which form potential targets for horizontal drilling. Increasingly more detailed paleogeographic maps are highlighting both the challenge and potential of the rich source rock in this basin.
This paper will cover how geochemical, structural, paleogeographic, petrophysical and other data are being used to derisk unconventional potential in this rich and complex rift system. Learnings from future testing of the Barmer Basin shale plays will be important to understand how to develop shale plays in other lacustrine rift basins.
Lin, Tengfei (Department of Middle East E&P, RIPED, PetroChina) | Wang, Nai (Department of Middle East E&P, RIPED, PetroChina) | Wang, Weijun (Department of Middle East E&P, RIPED, PetroChina) | Li, Nan (Department of Middle East E&P, RIPED, PetroChina) | Yang, Shuang (Department of Middle East E&P, RIPED, PetroChina) | Liu, Yumei (Department of Middle East E&P, RIPED, PetroChina) | Dong, Junchang (Department of Middle East E&P, RIPED, PetroChina) | Zhang, Qingchun (Department of Middle East E&P, RIPED, PetroChina) | Guo, Rui (Department of Middle East E&P, RIPED, PetroChina)
Bioclastic limestone reservoir is playing a dominant role in the petroleum industry of Middle East. The oilfield in this paper belongs to long-axis asymmetric anticline. The S formation of Cretaceous period universally developed bioclastic limestone of carbonate platform system. It is the reservoir heterogeneity that severely limits the oilfield development.
We firstly analyze the lithofacies based on the core and thin section. Then the detailed well and seismic interpretation illustrate the sequence stratigraphy and facies analysis, and tectonic evolution are analyzed to restore sedimentary procedure from Palaeocene to late Pliocene stage. Ultimately, high quality reservoir of bioclastic limestone are depicted according to comprehensive analysis.
This paper offers reference and inspiration for bioclastic limestone reservoir: reef-beach complex and sweet spots in tidal-channel are dominant reservoirs for bioclastic limestone of Middle East.
This paper presents the development and implementation of a production and power optimization system supported by a nodal analysis simulation tool and an updated and calibrated multiphase flow hydraulic model.
The workflow implemented in Castilla field identifies operating conditions that may affect the performance of 577 production wells configured in a complex gathering system, managing multiphase flow for heavy oil with low gas oil ratio and high water cut. Initially, this involves the development of a tool for the systematic data transfer from official databases to the simulation model. Furthermore, the hydraulic model was calibrated to reproduce operating conditions. And once the main nodes and boundary conditions at reservoir, wells, network and processing facility were defined, various optimization scenarios were simulated.
With this workflow the field engineers are capable to propose operating changes to increase production taking into consideration network bottlenecks, power consumption, and facilities limitations. The wells with electrical submersible pumps were ranked into the following categories: pump speed variation, well redesign, surface facilities improvement and drawdown limitation. As a result, actions to be implemented in each well were defined. First, ‘pump speed variation’ classified wells quickly demonstrated how the production and power optimization procedure benefit the field. Specifically, it was possible to optimize the extraction process by increasing the oil production up to 10% using power efficiently. Second, several bottlenecks on the network were identified finding atypical pressure drops, using traditional nodal analysis for pressure, temperatures, velocities, and liquid rates calculation per node. Some of them are related to mechanical configuration and others gas accumulation in pipelines. Third, according to the simulation results, a considerable amount of production can be gained and power consumption can be reduced if these conditions are solved.
This workflow contributes to optimize power consumption and enables faster decision-making to efficiently meet the production targets by increasing oil production and reducing water/oil and power/oil ratios.
The Gulf of Suez Basin (GOS), a World Class Hydrocarbon Province, is a typical Continental Rift, but many perplexities arise from the different proposed evolutionary models.
Previous models describe extension along (N)NW-(S)SE faults with antithetic half grabens, but show numerous difficulties to capture all observed elements into one single frame, as reconstruction is hampered by low seismic resolution below the heterogeneous Upper Miocene salt. Our analyses (from outcrop, seismic, well logs, gravimetry, magnetometry, dipmeter, and seismic and magnetic reprocessing), over the last years, allows the definition of a new tectonic model better describing these features: The GOS evolution is placed in a sinistral transtensional regime, reinterpreting the Duwi (WNW-ESE), Clysmic (NW-SE), Aqaba (NNE-SSW), and Cross (NE-SW) trends and the two (twist) accomodation zones, showing two distinct episodes resulting in overprinting of differently trending and tilting fault blocks. Furthermore it tackles perplexities related to the link between subsidence amounts/rates (backstripping), and extension, strain distribution, and episodes/pulses/unconformities. It describes the increase in extension towards the south in the rift-sphenochasm, and resolves the enigmatic relationship between high angle faults (that dominate the area), low angle dipping older faults and rotated pre-rift successions.
Our model foresees a two staged evolution: Initial rifting (Early Miocene - E1; Abu Zenima, Nukhul, Rudeis series) occurred along WNW-ESE trending (Duwi) faults disposed in an en-echelon manner as a result of a sinistral transtension. These faults progressively rotated in some areas towards a low angle with accompanied high angle "antithetic" tilted pre-rift strata. Subsidence accelerated during the Early Miocene, and some of these tilted fault blocks show erosion surfaces partly related to the final Early Miocene tectonic pulse. In a second stage (Mio- Pliocene - E2; Kareem, Belayim series, South Garib salt, Zeit evaporates) this pattern is overprinted by a new set of high angle rift faults trending (N)NW-(S)SE (Clysmic) cross-cutting the previous faults, but without any major block rotation. The Late Pliocene-Pleistocene (E3; Post Zeit, Shulher series) large (accelerating) differential uplift and subsidence, shows "synthetic tilting" of the strata along the rift margins, local tectonic inversion, syn- sedimentary detachment along the mobile salt layer with the generation of en-echelon ridges, generating the present day complex fault pattern (sigmoidal intervening trends and cross trends), and differently tilted smaller fault blocks. The new model is fully compatible with the pulsating NNE-NE movement of the Sinai Plate, associated with the NE moving Arabian Plate and Red Sea rifting, and has severe consequences for further Exploration and Development in the GOS, as it describes the configuration of the Hydrocarbon Fields in a more comprehensive way and predicts the occurrences of undiscovered Prospects.
An application at the forefront of the accelerating digitalization of offshore exploration and production (E&P) is remote condition monitoring (CM) of platform equipment, especially with a unique data-sampling technique called time stamping. CM tracks the performance data of equipment, watching for deviations from baseline performance benchmarks. Any unexpected variances from those established baselines may indicate a developing fault in systems found typically on offshore platforms. Technicians can then be dispatched to further investigate or service the equipment, targeting root causes of the variances—an approach called condition-based maintenance (CBM). The CBM approach has shown that it can improve reliability, availability, and asset use.
Kartawijaya, Ian Adrian (BP Indonesia) | Menanti, Yoseph (BP Indonesia) | Saraswaty, Dhita (BP Indonesia) | Suganda, Singgih (BP Indonesia) | Iqbal, Muhammad (BP Indonesia) | Anantokusumo, Ferry (BP Indonesia) | Dinata, Randy Chandrana (BP Indonesia)
Managing big gas well requires careful monitoring to ensure optimum wells production within their operating envelopes whilst continuously obtaining production data. Such data improves subsurface understanding over time and become a basis for optimization exercises, wellwork initiation, and quick corrective actions. Tangguh all-inclusive well surveillance integrates various daily data analysis into an efficient well surveillance process. It essentially looks for both early problem signs and improvement opportunities, enabling ahead anticipations.
Tangguh real time surveillance allows continuous parameter monitoring: pressures, temperatures, choke opening, multiphase flowrates, sand detection, annuli pressures, and system backpressure. A semi-automatic system then integrates all available data quickly and allow engineers to perform meaningful analysis timely. The integration is a significant upgrade over the past surveillance practice, where typically more time spent on data gathering instead of the analysis; and missing anomalies that happened in unmonitored parameters while concentrating on a specific parameter.
Combining with some non-routine data acquisitions, this well surveillance integration enables a quick and thorough well performance review and assists unlocking optimization opportunities. Three examples below demonstrate value creation from the integrated well surveillance.
First example: combining real time well data and the non-routine acquisitions enable robust well productivity model construction. This has improved the understanding of each well productivity and operating limits, which upon evaluating lead to deliverability increases by simple well limits upgrade and debottlenecking projects. Other result includes assistance in defining restoration wellwork candidate.
Second example: by continuous comparison between real time data and calculated performance model, the surveillance has shown its ability to detect well choke trim damage while flowing. This successfully prevented problem escalation into a more serious safety incident, such as gas release from an eroded choke valve.
Third example: despite the challenges in accurate dry-gas-well liquid rate measurement, continuous water source identification is applied honoring the significant reserve it may impact, starting from routine salinity monitoring, theoretical condensed comparison against receiving facility figures, and material balance plots. All positively indicate no aquifer breakthrough yet so far.
Batelaan, Okke (Flinders University) | Banks, Eddie (Flinders University) | Hatch, Michael (Flinders University) | Douangsavanh, Somphasith (Flinders University) | Sithiengtham, Phingsaliao (Flinders University) | Enemark, Trine (Flinders University) | Pavelic, Paul (International Water Management Institute) | Xayavong, Viengthong (National University of Laos) | Xayviliya, Ounakone (Department of Water Resources (DWR), Ministry of Natural Resources and Environment, Lao PDR)
Lao PDR is a poorly-developed country with a large rural population which relies almost exclusively on agricultural production systems as their means of livelihood. Even though surface water is abundant, Lao PDR is still vulnerable to the adverse effects of climate variability and climate change – flooding and heavy monsoon rains are common but the country also experiences
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: 204A (Anaheim Convention Center)
Presentation Type: Oral
Grover, Anurag (Abu Dhabi Company for Onshore Petroleum Operations Ltd.) | Muhairi, Layla Al (Abu Dhabi Company for Onshore Petroleum Operations Ltd.) | Al-Shabibi, Tariq Ali (Abu Dhabi Company for Onshore Petroleum Operations Ltd.) | Madhi, Ahmed El (Abu Dhabi Company for Onshore Petroleum Operations Ltd.) | Chakraborty, Subrata (Schlumberger) | Trudeng, Tone (Schlumberger) | Djuraev, Omon (Schlumberger)
This case study presents a systematic methodology applied for integrating tectonic history, image data, 3-D seismic data, geo-mechanical study to develop the Discrete Fracture Network (DFN) based 3D fracture model. Motivation for the present study was the limited understanding of permeability distribution in reservoirs. Dynamic behavior of the field from drilled wells indicated the possibility of presence of natural fractures in reservoirs. Fracture characterization study was embarked upon to build a reliable fracture model with the ultimate aim to improve on understanding of permeability distribution in reservoirs and to assist future dynamic flow simulation studies in the field.
The structural history of the field was analyzed to tie fracture related observations to the known tectonic events affecting reservoirs. Data analysis was done by attempting a simple structural restoration with available data. This analysis indicated two main tectonic events responsible for evolution of the present structure and the likely stress direction. Based on the tectonic history analysis, assumptions of a simplified plate-bending model and the Stearns model of fracturing related to folding have been applied during modeling. Available micro resistivity formation images from wells were interpreted for fracture type, fracture orientation & computation of fracture attribute. 3D seismic data was used to pick mappable faults & to generate the geometric seismic attributes. Variance attribute was selected for edge detection and was used to extract the Seismic Discontinuity Planes (SDPs). Faults in the reservoir & SDPs were further used as inputs to develop DFN. Fault related fractures were modeled using boundary element method based geo-mechanical approach which aims at computing maps of both natural fracture orientation and density trends, from observed major faults and observed fracture data along wells. Predicted tectonic models with stress directions show good match with the carried out structural geological analysis. Geo-mechanical model was used to estimates the breakability of rocks in reservoirs by computing Poisson's Ratio and Young's Modulus logs in several wells. 3D volumes of Young's Modulus and Poisson's Ratio were generated using Pre-Stack inversion results. Fold related fractures parallel to fold axes were modeled using the rock breakability predicted from Young's Modulus and Poisson's Ratio models calibrated with fractures interpreted from the wells. These fractures were constrained to the crestal part of the structure.
The 3D DFN based fracture model was up scaled into the 3D matrix model to generate the fracture porosity, fracture permeability tensors and the matrix to fracture communication factor. Multiple realizations of the fracture model were generated to capture the uncertainty associated with various aspects of this model. Fracture pore volume maps were generated for each reservoir and the specific recommendations were made about their use in dynamic history matching process.
Yonghui, Wang (Yan Xuemei Research Institute of Petrocleum Exploration and Development-Langfang, CNPC, National Energy Shale Gas R&D Experiment Center) | Zhuhong, Tian (Yan Xuemei Research Institute of Petrocleum Exploration and Development-Langfang, CNPC, National Energy Shale Gas R&D Experiment Center) | Lifeng, Yang (Yan Xuemei Research Institute of Petrocleum Exploration and Development-Langfang, CNPC, National Energy Shale Gas R&D Experiment Center) | Xingming, Yan (Yan Xuemei Research Institute of Petrocleum Exploration and Development-Langfang, CNPC, National Energy Shale Gas R&D Experiment Center) | Xinbin, Yi (Yan Xuemei Research Institute of Petrocleum Exploration and Development-Langfang, CNPC, National Energy Shale Gas R&D Experiment Center) | Haibing, Lu (Yan Xuemei Research Institute of Petrocleum Exploration and Development-Langfang, CNPC, National Energy Shale Gas R&D Experiment Center) | Yaoyao, Duan (Yan Xuemei Research Institute of Petrocleum Exploration and Development-Langfang, CNPC, National Energy Shale Gas R&D Experiment Center)
Scale development of shale gas in North America has greatly stimulated the enthusiasm of China. Since July 30, 2010 the first shale gas well fracturing, more than 300 wells have been fractured in the past five years in China, an average post-frac production is more than 6E4m3/d for one well. Technology include pre-frac evaluation, the methods of fracturing design, fracturing materials, tools and equipment, gas factory workflow and quality control system has formed.
Basis on the study following recognition can be drawn: ①natural fracture distribution stress difference and fluid viscosity are the key factors to create the complex fracture; ②geological engineering integration concept has been implemented and application successful; ③formulated the principle to improve SRV+3C (complexity, connective, conductivity), design method of shale gas reservoir stimulation has formed; ④formed including of transverse fracture to the horizontal wellbore set, PNP multi-stage fracturing, "the 3 big 2 low 1 small" (Large amount of liquid, proppant, high injection rate. Low fluid viscosity, sand concentration. Small diameter particle combination proppant) design, real-time quality control techniques, and multi-well simulfrac/zipperfrac technology, gas factory workflow, etc.; ⑤ construction capacity and parameters have reached the normal level of North America. Horizontal lateral up to 1000-2000m, single stage 60-100m, single well stages up to 25; For one stage fluid volume is generally 1600-2200 m3, proppant is normally 60-170t/stage, pumping rate is 8 -16 m3 / min; Usually for zipper-frac 2-4 stages can be finished in daytime, and 6 stages for simul-frac, post-frac production is from 6 to 55 (E4 m3/d) for a single well.
In this paper, not only successful experience on shale gas well fracturing are presented, but also some challenges, such as casing deformation, frature discription, water shortage etc.