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For years downhole monitoring and control have been widely used technologies to improve production and reservoir management. At the same time drilling technology has evolved and resulted in a rise of deep and complex multi-lateral wells. A well path may cover multiple production zones and connectivity between, and performance of production zones are often difficult to quantify. These challenges have contributed to a growing demand for information and control directly at the reservoir. This paper will show a reliable method to bridge the gap between the upper and lower completion for both control and data flow.
The method is a combination of two well proven systems, namely a cabled permanent downhole monitoring system that is connected to the surface with a tubing encapsulated conductor and instrumentation and control tools that are placed in the production zones of the laterals and are operated wirelessly. Extending the capabilities of both systems, a new wireless interface incorporated at the lower end of the cabled monitoring system enables duplex communication with the wireless instruments and tools in the lower completion. Communication between the wired system and wireless operated instruments may be based on acoustic or electromagnetic signals.
The combination of the two technologies provides an innovative new method to overcome the challenge of making a physical connection between the upper and lower completion for monitoring and control data transmission and may also be adapted to access instrumentation and controls in multiple laterals. The adaption of the technology is straightforward as the standard interface card is placed in a surface acquisition unit for dry trees and in the subsea control modules for wet trees. The interface card can send commands and log data from both the wired instrumentation in the upper completion and the wireless operated instruments and controls in the lower completion.
This study attempts to describe and model the process leading to the genesis of the tilted oil-water contact (OWC) observed in the lower part of the Thamama Group in an offshore Abu Dhabi field.
Post-oil-migration deformation is thought to be the mechanism that produced a tilted OWC dipping towards the Northeast. Deciphering the tectonic evolution from Jurassic to Paleocene times confirms a long and complex structural history combining burial, halokinesis, uplift and tilting. Diapiric activity was probably established in the eastern accumulation by pre-Jurassic times, followed by localized salt-related doming in both parts of the field. During the mid-Eocene occurred a late tilting of the northeastern part of the field, enhancing the curvature of the area.
This late tilting caused oil saturation redistribution. In uplifted areas of the field, water saturationdecreased along the drainage curve whereas in areas brought structurally closer to the Free Water Level (FWL), water saturation increased along a scanned imbibition curve.
The objective of this study is to retrace the saturation history of the field using lab-measured bounding capillary pressures. This workflow ensures the correct initialization of the dynamic reservoir model and reproduces the observed field behavior.
Drainage and imbibition capillary pressures are available for different rock types (RT), measured under various experimental set-ups (mercury injection, porous plate, centrifuge). This study reconciles lab measurements with wireline logs and Dean-Stark data to produce a representative capillary pressure curve for each RT.
Next, the structural deformation history is representedas a series of elementary geometric transformations (localized subsidence and global translation) to restore the reservoir in its pre-deformation state. Wireline log saturationsare matched to capillary-based water saturations by adjusting the present day free water level (FWL) and the change of FWL due to seepage.
The dynamic model is then initialized by enumeration with the original water saturation and let to equilibrate for 40,000 years. The fluid redistribution and pressures are then monitored to confirm that equilibrium has been attained. This equilibration step ensures that the fluids are at their correctstate of relative permeability and capillary pressure at the start of simulation, something that is not garanteed in the case of direct enumeration of the final saturations. The implications of such procedure on the dynamic behaviorare explored by simulating 50 years of production history and compa.
This study greatly improved the saturation modelling by moving from synthetic porosity-bin functions to physics and texture based capillary pressures. The proposed workflow enhanced the history-match quality and reproduced observed field behaviors such as the high water-cut development in the Northeast.
A tilted OWC might increase the in-place however extracting those resources might prove more challenging in the face of the low oil mobility. The oil below OWC might not be recovered under conventional waterflood methods and would warrant an EOR implementation. In the future, an appraisal well is planned in the Northeast to assess the volume and mobility of the oil below OWC.
It is the first time an integrated workflow, combining SCAL and structural geology, is proposed to correctly initialize the dynamic model for reservoirs that experienced a post-migration deformation, hence making the present study unique.
Khan, Sameer A. (ExxonMobil Iraq Services Limited) | Hassan, Fadhel A. (ExxonMobil Iraq Services Limited) | Wang, Junwen (ExxonMobil Iraq Services Limited) | Gan, Junqi (ExxonMobil Iraq Services Limited) | Liu, Yang (ExxonMobil Iraq Services Limited) | Patz, Joseph F. (ExxonMobil Iraq Services Limited) | Abdulshbeb, Saeb K. (Basra Oil Company) | Al Lawe, Erfan M. (Basra Oil Company)
This work encompasses redevelopment of a supergiant southern Iraqi oil field from fully vertical to primarily horizontal wells. The subject reservoir is a massive world-class carbonate limestone reservoir containing 23 °API oil and is the dominant reservoir in a set of vertically stacked reservoirs. This reservoir is a part of a large anticline which is oriented north-northwest. The formation is Middle Cretaceous and has a subsea depth of 2100–2600 m. The reservoir was initially developed on a 200 acre inverted 9-spot pattern, and was on primary oil production until reservoir pressure dropped and production declined. Later, water injection started at centers of the 9-spot pattern. Development drilling was projected with future addition of vertical infills at 100 and then 50 acre patterns.
During pressure drop due to primary production, water encroachment from flanks occurred, particularly, in the thin super-high permeability (vuggy) layers present in the reservoir; however, this was not clearly evident at early stages. By the time of starting pattern water injection with comingled injection and production in vertical wells, there was clear evidence of rapid water movement in the vuggy layers. As water injection progressed, the severity of watercut evolution in vertical wells rapidly progressed, necessitating change of the depletion plan. Continued development of the field with vertical infills would result in unsustainable water production and injection requirements, and lower oil recovery.
A redevelopment effort was initiated to overcome these challenges. Geologic and simulation models were modified to reflect the evolved understanding of geology. Appropriate distribution of high permeability layers was introduced and calibrated to production data, in particular, water breakthrough timing and watercut evolution. The main change in the redevelopment plan has been to shift emphasis from drilling vertical infill wells to a fewer horizontal wells targeting low permeability zones which comprise most of the reserves. Reservoir development of the massive lower section is planned with 2 km long horizontal wells with injectors located in lower part of the reservoir and producers higher arranged in a line drive. Upper reservoir development is planned by working over existing comingled vertical wells to upper reservoir only thus decoupling upper and lower comingled production.
The redevelopment plan achieves the business target rate with a much longer plateau duration at lower cost. The plan effectively utilizes existing vertical wells in addition to drilling new horizontal wells for recovering oil from lower, tighter reservoir. Initial performance of horizontal wells have shown very promising results with boosted dry oil production. This updated development plan is now in full execution phase and can provide redevelopment ideas for other brown fields with similar issues.
Reservoir development using Maximum Reservoir Contact (MRC) wells has taken significant leaps and bounds in the oil and gas industry in the last fifteen years with horizontal well length of more than 2500 meters. MRCs, a breakthrough in drilling technology, has enabled us to drill long horizontal producing or injecting sections, especially in low permeability or tight oil bearing layers. In such reservoirs, with the increased reservoir contact surface area, the wells are able to produce and inject at higher rates with lesser drawdowns. This increased productivity index helps to delay the gas and water breakthrough, reduce the conning and improve the GOR/Water-cut response. Hence, improving the sweep efficiency and the ultimate recoveries. On the other hand, MRC wells could potentially help to address the subsurface and surface congestion challenges especially in brown fields by reducing the overall development well count by 2 to 3 times.
The production gain from long horizontal section is limited by the pressure drop within the well bore from toe to heel. Therefore, there is a technical limit to the production gain that can be achieved by increasing the horizontal section length. Drilling beyond this limit will incur cost without any prominent production gains. Hence, there would be a techno-economic limit to the optimal MRC well length.
This paper present the screening study conducted to determine the optimal well length for an MRC well from a techno-economic point of view. A mechanistic fine gridded sector simulation model is used for this study. The MRC wells are segmented and considers the well bore hydraulic calculations for all the pressure loss elements. Different MRC well length scenarios are considered to compare the sweep efficiency and ultimate recoveries. The cost to benefit screening analysis is conducted for various MRC lengths, in relation with their associated costs and dynamic performance.
The techno-economic analysis indicates that the MRC well length of around 10K ft is the optimal. Beyond this length, there is a marginal increase in incremental NPV and the relative difference in reduction of UTC gets minimal.
The paper highlights the importance of a value assurance study conducted for the MRC well lengths that can potentially be considered for optimal field development/re-development. Each reservoir with its specific rock and fluid characteristics would worth this type of screening study with the help of numerical simulation tools. The choice of MRC well length would eventually have a great impact on the field development economics.
The main objective of the research presented in this paper was to develop a working knowledge of the unconventional shale in the UAE Diyab formation which includes reservoir engineering evaluation of the UAE Diyab Upper Jurassic gas condensate and Shilaif Middle Cretaceous light oil shale development. To achieve this objective, (1) we measured core permeability of a couple of Diyab cores with and without fractures, (2) we analyzed the pressure fall-off data from a Diagnostic Fracture Injection Test (DFIT) to determine in-situ
We concluded that our research effort was both informative and instructive in determining the effectiveness of the stimulation efforts for the wells used in this study, and the process can be similarly utilized in any shale stimulation effort elsewhere.
Smart completions enable physical measurements over space and time, which provides large volumes of information at unprecedented rates. However, optimizing inflow control valve (ICV) settings of smart multilateral wells is a challenging task. Traditionally, ICV field tests, evaluating well performance at different ICV settings, are conducted to observe flow behavior and configure ICV's, however this is often suboptimal. This study investigated a surrogate-based optimization algorithm that minimizes the number of ICV field tests required, predicts well performance of all unseen combination of ICV settings, and determines the optimal ICV setting and net present value (NPV).
A numerical model of a real offshore field in Saudi Arabia was used to generate scenarios involving a two-phase (oil and water) reservoir with trilateral producers. Multiple scenarios were examined with variations in design parameters, mainly well count, placement and configuration. Eight discrete settings were assumed to match the commonly installed ICV technology, where all possible scenarios were simulated to establish ground truth. The investigation considered three major algorithmic components: sampling, machine learning, and optimization. The sampling strategy compared physics-based initialization, space-filling sampling, and triangulation-based adaptive sampling. A cross-validated neural network was used to fit a surrogate dynamically, while enumeration was adopted for optimization to avoid errors arising from using common optimizers.
This study evaluated two sampling techniques: space-filling and adaptive sampling. The latter was found superior in capturing reservoir behavior with the smallest number of simulation runs, i.e. ICV field tests. Algorithm performance was evaluated based on the number of ICV field tests required to: 1) surpass an R2 threshold of 0.9 on all unseen scenarios, and 2) match the optimal ICV settings and NPV. Surface and downhole flow profile prediction and optimization were achieved successfully using this approach. To determine the diminishing value of additional ICV field tests, the triangulation sampling loss was used as a stoppage criterion. When running the algorithm on a single producer for both surface and downhole oil and water flow prediction, the algorithm required six and 11 ICV field tests only to achieve 80% and 90% R2 across the different cases of this real reservoir model. Fishbone wellbore configurations were found to pose a more challenging task as changes in any ICV pressure drop affects multiple laterals simultaneously, which increases the level of interdependence. The resultant surrogate was used to decide on the optimal settings of ICV devices and also predict the NPV effectively. Further improvement was accomplished through adaptively sampling and fitting surrogate to rather predict NPV explicitly where NPV predictions were generated with nearly 95% R2 given only ten ICV field tests.
Using adaptive sampling and machine learning proved effective in the prediction of surface and downhole flow profiles, and optimization of smart wells. The method further allows for dynamically optimizing field strategy in a reinforcement learning setting where production data are used continuously to further improve the prediction performance.
Iron sulfide scale deposition can be a significant flow-assurance issue in sour-gas production systems. It can deposit along the waterflowing path from the near-wellbore reservoir region to the surface equipment, which results in formation damage, causes tubing blockage, interferes with well intervention, and reduces hydrocarbon production.
The main objectives of this paper are to review the new advancements and remaining challenges concerning iron sulfide management in sour-gas wells, covering the mechanisms of iron sulfide formation, the mechanical and chemical removal techniques, and the prevention strategies.
In this paper we give a special emphasis to the different mechanisms of iron sulfide formation during well-completion and production stages, especially the sources of ferrous iron (Fe2+) for scale deposition. It is essential to understand the root cause to identify and develop suitable technologies to manage the scale problem. We also summarize the latest developments in mechanical methods and chemical dissolvers for the removal of iron sulfide deposited on downhole tubing. The capabilities of the current chemical dissolvers are discussed, and the criteria for effective dissolvers are provided to serve as guides for future development. Then, we provide an overview of recent developments on iron sulfide prevention technologies and treatment strategies. We differentiate the treatment approaches for corrosion byproduct and scale precipitation and scale-inhibitor deployment through continuous-injection and squeeze treatments. Finally, we outline the technical gaps and areas for further research-and-development (R&D) efforts.
We provide the latest review on iron sulfide formation and mitigation, with an attempt to integrate viable solutions and showcase workable practices.
Wang, Cai (RIPED CNPC) | Xiong, Chunming (RIPED CNPC) | Zhao, Hanjun (PetroChina Exploration & Production Company) | Zhao, Ruidong (RIPED CNPC) | Shi, Junfeng (RIPED CNPC) | Zhang, Jianjun (RIPED CNPC) | Zhang, Xishun (RIPED CNPC) | Huang, Hongxing (NCCBM) | Chen, Shiwen (RIPED CNPC) | Peng, Yi (RIPED CNPC) | Sun, Yizhen (RIPED CNPC)
Sucker-rod pumping wells are the most widely used producing wells in China. 94% of the 200,000 oil wells in CNPC are sucker-rod pumping wells. It is urgent to reduce the cost of every single well based on the well diagnosis and optimization methods under the background of low oil price and the IoT. Rich working experience of field engineers could help them diagnose some conspicuous abnormal well conditions by electrical power curves easily, but the scientific diagnosis methods have still not be established, and the potential of electrical power curves of the producing well is far from being fully tapped.
The aim of this work is to diagnose the working condition of the sucker-rod pumping wells both on and under the ground based on the data from electrical power curves by machine learning. The methods shaped by the learning of the electrical power curves from nearly 600 wells mainly separate into 3 steps. The first is the diagnosis of conspicuous abnormal well conditions such as motor belt burning, motor belt slippage, two phase electrics, upper rod break, lower rod break et al. The prediction experience was obtained from the statistical learning of the mean and variance values after we equally split the 600 power curve values into 10 sub-groups. The second is the diagnosis of complex abnormal well conditions such as abnormal mechanical sound, slight tube leak, severe tube leak, pump stuck et al based on the combination of statistics and template vs diagnosed sample analysis. The third is the diagnosis of pumping conditions characterized by the remarkable prediction ability via deep learning. A surface well condition database was established and the corresponding electrical power curves were marked in real time. Based on the CNN technology, the model could recognize different pump working conditions such as insufficient liquid, gas influence, traveling valve leak, standing valve leak et al very well.
The work has been applied in the oil fields of Jilin and Daqing. The method has been tested on nearly thousand hundreds of producing well utilizing sucker rod pumping system. The model demonstrates very high accuracy with almost 90% similarity to the result diagnosed by corresponding pump dynamometers for large sample and 94% of abnormal well working conditions for small sample. What’s more, the work would reduce millions of investment on the sensors, equipment and manpower for the management of producing wells in CNPC each year in the context of industrial IoT.
Learn more about training courses being offered. Learn more about training courses being offered. This course covers the fundamental principles concerning how hydraulic fracturing treatments can be used to stimulate oil and gas wells. It includes discussions on how to select wells for stimulation, what controls fracture propagation, fracture width, etc., how to develop data sets, and how to calculate fracture dimensions. The course also covers information concerning fracturing fluids, propping agents, and how to design and pump successful fracturing treatments. Learn more about training courses being offered. Current and future SPE Section and Student Chapter leaders are invited to engage and share.
The chief upstream strategist of IHS Markit said in a recent presentation that oil exploration must improve its ability to deliver value and better communicate that value to the financial community. New ways of thinking about exploration opportunities are needed. Producers in Oklahoma’s newly opened Merge play are sitting atop a resource that rivals some major world gas fields and discoveries, Citizen Energy’s Geology CEO Greg Augsburger told the SPE Gulf Coast Section Business Development Group recently. The Austin Chalk play could go through a revival if the industry can view the formation through “a fresh set of eyes,” says EnerVest’s Tony Maranto. Dimethyl-ether (DME) -enhanced waterflood (DEW) is a process in which DME is added to injection water and, upon injection, preferentially partitions into the remaining oil.