The key technical considerations and decisions involved in selecting a progressing cavity pump(PCP) for a particular application include pump displacement, pressure capability, geometric design, elastomer type, and rotor coating characteristics. Other factors, such as local vendor choice and economics can also affect pump selection. Figure 1 provides a flow chart of the key decisions. When selecting a PC pump, the two most critical requirements are adequate displacement capacity and pressure capability to ensure that the pump can deliver the required fluid rate and net lift for the intended application. It is typical to select pumps with a design (i.e., theoretical) flow rate that is somewhat higher than the expected fluid rate to reflect pump inefficiencies during production operations.
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.
The Jurassic age Hanifa and Tuwaiq Mountain Formations are regionally established source rocks that charged majority of the oil fields in the region. These formations are comprised of dark carbonate mudrocks with high organic richness and dominantly calcite mineralogy. Several studies were conducted regionally to evaluate the potential of these Jurassic intervals as an unconventional play.
In April 2018, The Kingdom of Bahrain announced the discovery of a major unconventional resource in Khalij Al Bahrain basin following the production of light oil from Tuwaiq Mountain Formation. These results confirmed the viability of the Jurassic source intervals as an Unconventional asset. However, the nature and the location of the resource present a number of operational challenges in a region where development of unconventional resources is at its infancy. This instigates the need to address and tackle these challenges through innovative approaches to enable the effective appraisal and subsequently development of the asset.
This publication introduces the emerging unconventional play in Khalij Al Bahrain basin and discusses the adopted strategies to appraise and develop the asset. The areas for optimization considered include well design, drilling and completion, facilities and shallow offshore/onshore logistics.
The Hanifa and Tuwaiq Mountain formations are Jurassic in age (Figure 1) and consist of a mixed section of dark organic rich limestone beds. These formations are regionally established as the principle source rock that charged majority of the overlying Jurassic reservoirs in the region, and in Bahrain, the cretaceous reservoirs as well. These source rocks are the main targets of the recently discovered Khalij Al Bahrain (KAB) basin in Bahrain with initial resource estimates indicating potentially up to 80 billion barrels of unconventional oil and 14 trillion cubic feet of gas in place.
Location and Geological Settings
KAB basin is located in the eastern part of the Arabian basin straddling the area towards the east of Saudi Arabia, west of Qatar Arch and south of the Zagros fold belts. Majority of the basin today falls within the land bound shallow waters around the main island of Bahrain. Major fields in the area include Awali, Dukhan and Abu Safah which are likely to have been sourced from these Jurassic source rocks (Figure 2). KAB basin also lies in close proximity to the Jafurah basin which is a significant Jurassic unconventional play in Saudi Arabia targeting the same formations .
Gas lift is especially suited for application in unusual environments. This page discusses a few of these environments and how gas lift is used in the particular application. Gas lift is a widely used artificial-lift system in offshore installations and has performed exceptionally well. Most downhole gas lift equipment has few if any moving parts and requires little maintenance. For this reason, downhole gas lift equipment is much less costly to replace than other forms of downhole artificial-lift equipment.
In the past, much of the petrophysics done in the Australian mining industry has been based upon gamma ray, simple density devices, resistivity, and televiewers. Common uses of petrophysical data include locating the top and bottom of the seam/ore, determining the water level, mapping fractures and faults, computing hardness, and facies analysis. However, the industry is moving toward more advanced applications, such as improved methods of understanding the porosity and permeability of the rocks, 3D mapping of stability, and the use of petrophysical measurements as a cost-effective means of supplementing or even replacing traditional assay methods.
This paper begins with a brief introduction to the mining environment as compared with the modern oilfield environment. While petrophysical data acquisition in East Australian coal mines is not so far removed from shallow oilfield land wells, open pit mines, such as the Pilbara Iron Ore fields of Western Australia are a very different world - thousands of holes are drilled, each generally less than 60 metres. Assays (geological analysis of material collected from the hole) are the primary reference data. Costs to log are low and many processes (data interpretation, delivery of logs, etc.) are automated.
Next we will review how gamma ray, density, neutron, resistivity, and caliper measurements are used throughout the Australian mining industry, paying some attention to the challenges of using classic tool designs such as 16/64 normal resistivity tools and single point (uncompensated) density. Sonic, electrical imaging, and optical televiewers are the next tier of measurements, used for fracture/fault mapping, ground stability, hardness and seismic integration. Finally, we will discuss the latest wave of technologies to be gaining ground in the Australian mining market, including NMR, VSP, and elemental spectroscopy.
The introduction of advanced petrophysical measurements in Australian mining is opening the door for exploiting new applications, many centered around “big data” or machine learning techniques, such as automated facies identification, high resolution mapping of both major and minor minerals, and 3D visualisation of ore properties.
The operator piloted a new well-completion design combining inflow-control valves (ICVs) in the shallow reservoir and inflow-control devices (ICDs) in the deeper reservoir, both deployed in a water-injector well for the first time in the company’s experience. In this paper, the authors describe a project to design, field trial, and qualify an alternative solution for real-time monitoring of the oil rim in carbonate reservoirs that overcomes these disadvantages. The authors detail the development of a technique based on surface-to-borehole controlled-source electromagnetics (CSEM), which exploits the large contrast in resistivity between injected water and oil to derive 3D resistivity distributions, proportional to saturations, in the reservoir. This industry is one often considered reactive and overly tradition-bound. These new technologies, however—and, more importantly, the drive of these researchers to harness their capabilities—prove that petroleum engineers remain at the forefront of innovation and discovery.
Africa (Sub-Sahara) Shell has initiated a two-well drilling program in blocks 1 and 4 of the Mafia Deep basin offshore Tanzania. Drilling is taking place in water depths of up to 7,545 ft, with the company and its joint-venture partners Pavilion Energy and Ophir Energy investing almost USD 80 million in the program. The two wells will meet the remaining requirements in the exploration licenses issued by the Tanzanian Ministry of Energy and Minerals. Asia Pacific Petronas has begun gas production from the world's first floating liquefied natural gas (FLNG) facility, the PFLNG SATU, at the Kanowit field offshore Malaysia's Sarawak state. The first-gas milestone marked the onset of commissioning and startup for the FLNG facility, preceding commercial production and initial cargo shipment. The facility is fitted with an external turret for operating in water depths of 229 ft to 656 ft. It will extract gas through a flexible subsea pipeline for the liquefaction, production, storage, and offloading of LNG at the field.
BP, through its BP Trinidad & Tobago (BPTT) joint venture, has made two significant gas discoveries with the Savannah and Macadamia exploration wells offshore Trinidad. Together they represent the discovery of 2 Tcf of gas in place. BPTT expects to develop these reservoirs through a future tieback to the Juniper platform that is due to come on line in mid‑2017. The Macadamia well encountered approximately 600 ft of net pay in seven intervals. The discovery is expected to support a new platform development sometime after 2020.
In comparison to Steam-Assisted Gravity-Drainage (SAGD), the technique of injecting of warm solvent vapor into the formation for heavy oil production offers many advantages, including lower capital and operational costs, reduced water usage, and less greenhouse gas emission. However, to select the optimal operational parameters for this process in heterogeneous reservoirs is non-trivial, as it involves the optimization of multiple distinct objectives including oil production, solvent recovery (efficiency), and solvent-oil ratio. Traditional optimization approaches that aggregate numerous competing objectives into a single weighted objective would often fail to identify the optimal solutions when several objectives are conflicting. This work aims to develop a hybrid optimization framework involving Pareto-based multiple objective optimization (MOO) techniques for the design of warm solvent injection (WSI) operations in heterogeneous reservoirs.
First, a set of synthetic WSI models are constructed based on field data gathered from several typical Athabasca oil sands reservoirs. Dynamic gridding technique is employed to balance the modeling accuracy and simulation time. Effects of reservoir heterogeneities introduced by shale barriers on solvent efficiency are systematically investigated. Next, a state-of-the-art MOO technique, non-dominated sorting genetic algorithm II, is employed to optimize several operational parameters, such as bottomhole pressures, based on multiple design objectives. In order to reduce the computational cost associated with a large number of numerical flow simulations and to improve the overall convergence speed, several proxy models (e.g., response surface methodology and artificial neural network) are integrated into the optimization workflow to evaluate the objective functions.
The study demonstrates the potential impacts of reservoir heterogeneities on the WSI process. Models with different heterogeneity settings are examined. The results reveal that the impacts of shale barriers may be more/less evident under different circumstances. The proxy models can be successfully constructed using a small number of simulations. The implementation of proxy models significantly reduces the modeling time and storages required during the optimization process. The developed workflow is capable of identifying a set of Pareto-optimal operational parameters over a wide range of reservoir and production conditions.
This study offers a computationally-efficient workflow for determining a set of optimum operational parameters relevant to warm solvent injection process. It takes into account the tradeoffs and interactions between multiple competing objectives. Compared with other conventional optimization strategies, the proposed workflow requires fewer costly simulations and facilitates the optimization of multiple objectives simultaneously. The proposed hybrid framework can be extended to optimize operating conditions for other recovery processes.