This paper describes a trial project to evaluate autonomous inflow control device (AICD) technology to better manage water production in a large heavy oil field in Colombia. The Cajua block is part of the Rubiales field is in the Llanos basin of Eastern Colombia, and has reserves estimated at 7.5 billion barrels. One of the main production challenges is the high water cut, or BSW, driven by strong aquifer flow in the underlying sands of the Carbonera formation. Many wells experience early water break-through and must be produced above 95% BSW for long periods of time. Horizontal wells typically produce up to 8000 barrels per day of total fluid with electric submersible pump (ESP) on cold production, and do not utilize any thermal recovery methods. The loosely-consolidated sandstone reservoir has variable water saturation and permeability, which has continuously frustrated operators'’ attempts to manage water production ever since the Rubiales field was first brought online in the 1980's.
In late 2018, a three well pilot project was initiated to evaluate the ability of inflow control technology to manage water influx at the sandface of the horizontal completions. Three wells in the Cajua block were equipped with AICD screens and swellable packers to evaluate oil production and water cut. The AICD technology works by limiting water inflow based on fluid viscosity. Each segment, or compartment, of the horizontal wellbore is isolated by swellable packers, and the AICD creates a higher or lower drawdown on the reservoir depending on the fluid properties, favoring the inflow of high-viscosity heavy oil over the low-viscosity water.
The early production results show that AICD completions can effectively manage water production by delaying water break-through and restricting water inflow from the reservoir. Each of the three trial wells responded positively to the autonomous ICDs, allowing engineers to produce heavy oil wells more effectively with lower cumulative water volumes.
This project marks the first implementation in South America of AICD technology with rate-controlled production (RCP) valves to manage water production in a heavy oil field. It is also the second application worldwide, after Canada, to show that AICDs can effectively to manage water cut in a heavy oil, cold-production scenario.
Ketineni, Sarath Pavan (Chevron Corporation) | Tan, Yunhui (Chevron Corporation) | Hoffman, Katrina L. (Chevron Corporation) | Jones, Matthew (Chevron Corporation) | Ghoraishy, Mojtaba (Chevron Corporation)
Demonstrating the viability of multistage hydraulic fractured horizontal wells to unlock otherwise trapped resources is presented through a case study on Rangely. A combination of high-fidelity reservoir models was employed for accurate forecasts and evaluation of hydraulically fractured horizontal wells to improve resources in this mature conventional oil field with ongoing pressure support and tertiary recovery operations. The modeling techniques used in this method can be extended to other mature oil fields to unlock bypassed oil setting a precedent to re-evaluate mature oil fields with the new unconventional completion technologies.
The Rangely Weber Sand Unit is an Eolian sandstone depositional system consisting of 2 billion bbls of oil in place. The Weber Formation is Pennsylvanian to Permian in age, and typically consists of fine-grained and cross bedded calcareous sandstones. Structurally oil is trapped in an anticline with varying dip angles on the flanks. The oil production from this reservoir was managed through primary depletion for the first two decades of production followed by secondary recovery via water flood and concluding through water alternating CO2 injection (WAG) over the last three decades. Due to the heterogeneity in depositional environment, the recovery factors have been low in the eastern end of the field. The east end of the field has relatively lower permeability and lower porosity compared to the rest of the field. A modeling workflow is presented to assist with evaluation and optimization of hydraulically fractured horizontal infill wells to recover bypassed oil in the eastern end of the Rangely field.
A full fidelity static model was built based on dense, high quality well control data. A sector model was history matched, and then used to update pressure, saturations, and stress distribution to present day. The history matched model was subsequently used to evaluate horizontal well performance and hydraulic fracturing completion options to overcome these heterogeneities and improve recovery from a lower quality reservoir.
Completions optimization opportunities were focused on fracture geometry, incremental Estimated Ultimate Recovery (EUR), and economics. Sensitivity studies demonstrated that an optimal balance of cost and recovery is found at the low end of fracture volumes and wider perforation cluster spacing. Forecasting runs show incremental economic recovery which otherwise could not have been recovered through ongoing WAG operations.
While many factors in the reservoir cannot be controlled, there are three controllable factors in field development that make a significant impact. More reservoir contact leads to more oil produced. Controlling sand and water means lower treatment costs, and in-situ reservoir management leads to higher cumulative production. While the underlying technologies have been around for up to 20 years, it is only recently that their synergies and true value are understood. This paper will demonstrate the effect each of these technologies has on increasing overall production rates, improving recovery, and reducing the cost per Barrel of Oil Equivalent (BOE).
The successful implementation of multilaterals in the North Sea will be analyzed. Since 1996, over 300 multilateral junctions have been installed on the Norwegian continental shelf fields with currently approximately 30 junctions completed each year.
Additionally, simulations will be used to demonstrate the incremental improvements in oil recovery that can be obtained by using properly designed advanced completions that include multilaterals, sensors, and passive/active flow control equipment.
The paper will evaluate production performance of a vertical well field development base case against scenarios using horizontal and multilateral wells. It will show how fields can be optimized, leading to increased oil and decreased water production.
Production rates can be significantly improved by combining multilaterals with other advanced completion techniques, such as intelligent completions and inflow control devices. The subject field simulation can be further optimized to manage gas and water production.
With a tailored multilateral field design, combined with properly designed advanced completions systems, the simulation succeeds in terms of achieving maximum contact with the oil reservoir and meeting improved ultimate recovery objectives.
It can be concluded that as reservoir contact is increased, a reduced decline in production rate is observed leading to both a higher Estimated Ultimate Recovery (EUR) and optimized drawdown profile distributions. Additionally, results will be presented that have considered oil production and a method to lower production of unwanted fluids or gas.
This paper also demonstrates the value of field development design from the perspective of reservoir simulation. It is through reservoir insight that a level of understanding is created that can help define the optimum well and completion design to meet field expectations.
Advanced multilaterals continue to grow in popularity with many operators, and it therefore becomes important to evaluate the value of different field development methods. This knowledge can aid operators in unlocking new reservoir targets and optimizing field development, and ultimately will improve recovery factors and overall field economics.
The Stavanger Young E&P Professionals (YEPP) group started up in November 2004. The launch event got the section going with a bang when we visited ConocoPhillips' Onshore Drilling and Operation Center in Tananger. The use of real-time centers of the type pioneered by ConocoPhillips is extremely important in Norway because the drive for reduced costs continues and large late-life production infrastructure projects make bed spaces a premium commodity offshore. In December, we visited Halliburton, where we learned about multilateral wells, especially those in use in the Troll field. These wells are helping Hydro increase its reservoir exposure from approximately 10km per well to its target of 20km, and all within a reservoir section that is at times just 11m thick.
Downhole control devices are being widely implemented in fields globally; and, because of the costs involved in their implementation, a robust reservoir performance forecast is necessary. A prerequisite to a sound reservoir development plan is to have a robust history-matched reservoir simulation model. This study involves use of a downhole inflow control device (ICD) well configuration in the reservoir simulation model to perform history matching of a green-field offshore Abu Dhabi. The results of this approach are compared to the results from traditional approaches. The scope of this study is to examine the differences in both history match approaches.
Reservoir A is one of the major reservoirs of a green-field located offshore Abu Dhabi, and is being developed with a five-spot water injection pattern. The producers and water injectors are horizontal wells, which are drilled across different flow units within the reservoir. Because the reservoir is heterogeneous across all the flow units, the injection pattern results in a non-uniform water front. The conventional approach to history matching the well performance is to implement a positive skin factor across the well completions to mimic the effect of the inflow control devices (ICDs) installed in the well: increasing the pressure drop (ΔP) between the formation and the well tubing. In this study, the actual downhole configuration was prepared using well-completion analysis software, followed by use of a next-generation reservoir simulator to run the full field reservoir model for the history matching period.
As the field is being developed on the principles of digital concept, continuous high-frequency downhole pressure data is available in flowing as well as shut-in conditions. The use of this data, coupled with direct modeling of the ICDs in the simulation model, resulted in a significant improvement in the reliability of the history match, as compared to traditional approaches.
This study compares two history matching approaches for fields with wells completed with downhole control devices. The core purpose of this study is to integrate the principles of the digital oil field with conventional history matching techniques, with the ultimate goal of improving the history match.
A study using a dynamic multiphase-flow software simulated a rapid-unloading event and determined the gas fraction in the riser annulus and the effect on riser fluid levels. The Troll field is one of the largest gas producers discovered off Norway, but ensuring its long-term future required finding ways to drill wells in an increasingly fragile formation to develop its rich oil reserves. The list of wells drilled using dual gradient includes one drilled in the “eastern Gulf of Mexico,” which could be more precisely described as offshore Cuba. A previous attempt to drill an exploration well in ultradeep water in the Gulf of Mexico (GOM) did not reach its objective.
Will Blockchain Become the New Operational Backbone in Energy? Energy companies are looking to distributed ledger technology—otherwise known as blockchain—to help navigate the complex transactional systems that make up their operations. What is blockchain, and what makes it valuable to our industry? Statoil’s integrated operations center on the Norwegian continental shelf is one of several initiatives operators and service companies have set in motion to improve condition monitoring and maximize production on their assets. The company’s 31 licenses highlight a record-high total awarded during the latest APA round, which is aimed at developing mature areas of the NCS.
This paper describes challenges faced in a company’s first deepwater asset in Malaysia and the methods used to overcome these issues in the planning stage. This paper discusses the successful application of managed-pressure drilling (MPD) in the basin with reduction in risks and well costs. This paper discusses how managed-pressure-drilling (MPD) technology led to cost savings in two wells drilled in the Hai Thach gas field offshore southern Vietnam. This paper describes how a technique known as applied-surface-backpressure managed-pressure drilling (ASBP-MPD) can alleviate the limitations of conventional deepwater well control. The complete paper describes a recent directional coiled-tubing drilling (DCTD) job completed for an independent operator in the Appalachian Basin.
Saudi Aramco awarded a contract* to McDermott International for engineering, procurement, constructi ... DNV GL has won a contract to provide independent verification services for Energinet’s section of th ... Equinor has awarded Subsea 7 with an engineering, procurement, construction, and installation (EPCI) ... Malaysian FPSO provider Yinson has secured a long-term contract extension through October 2022 with ... Well-Safe Solutions has been awarded a contract to decommission as many as 21 wells on the DNO-opera ... Infinity Oilfield Services and Medserv have formed a new joint venture named InMedCo to provide a po ... Boskalis Subsea Services said it has been awarded more than £100 million ($126 million) in contracts ... Chevron Australia has awarded Wood with a new contract to provide subsea integration and flow assura ... Qatar Petroleum has awarded McDermott with the FEED contract for the offshore pipelines and topsides ... DOF Subsea has secured two contracts in Brazil. Source: Teekay Offshore Teekay Offshore has agreed to a 3-year contract ... Petrobras has awarded TechnipFMC with an engineering, procurement, construction, and installation (E ... ADNOC awarded a $1.36-billion dredging, land reclamation, and marine construction contract to the UA ... Wood and KBR inked a multimillion-dollar contract to deliver integrated front-end engineering design ... Anadarko Mozambique Area 1, LTDA, a subsidiary of Anadarko Petroleum Corp., named the preferred tend ...
Thin oil columns overlain by free gas and underlain by water pose difficult problems in well spacing and completion method, production policy, and reserves estimation. In this context, "thin" is a relative term. Whether an oil column is considered thin depends on costs to drill and produce the accumulation. For example, in the Bream field (Australia Bass Strait, 230 ft water depth), 44 ft was considered thin, whereas in the Troll field (offshore Norway, 980 ft water depth), 79 ft was considered thin. Onshore U.S.A., 20 ft is considered thin. Irrgang takes a pragmatic approach, defining thin oil columns as those that "will cone both water and gas when produced at commercial rates."