Unlocking By-Passed Oil with Autonomous Inflow Control Devices Through an Integrated Approach

In a giant offshore UAE carbonate oil field, challenges related to advanced maturity, presence of a huge gas-cap and reservoir heterogeneities have impacted production performance. More than 30% of oil producers are closed due to gas front advance and this percentage is increasing with time. The viability of future developments is highly impacted by lower completion design and ways to limit gas breakthrough. Autonomous inflow-control devices (AICD's) are seen as a viable lower completion method to mitigate gas production while allowing oil production, but their effect on pressure drawdown must be carefully accounted for, in a context of particularly high export pressure. A first AICD completion was tested in 2020, after a careful selection amongst high-GOR wells and a diagnosis of underlying gas production mechanisms. The selected pilot is an open-hole horizontal drain closed due to high GOR. Its production profile was investigated through a baseline production log. Several AICD designs were simulated using a nodal analysis model to account for the export pressure. Reservoir simulation was used to evaluate the long-term performance of short-listed scenarios. The integrated process involved all disciplines, from geology, reservoir engineering, petrophysics, to petroleum and completion engineering. In the finally selected design, only the high-permeability heel part of the horizontal drain was covered by AICDs, whereas the rest was completed with pre-perforated liner intervals, separated with swell packers. It was considered that a balance between gas isolation and pressure draw-down reduction had to be found to ensure production viability for such pilot evaluation. Subsequent to the re-completion, the well could be produced at low GOR, and a second production log confirmed the effectiveness of AICDs in isolating free gas production, while enhancing healthy oil production from the deeper part of the drain. Continuous production monitoring, and other flow profile surveys, will complete the evaluation of AICD effectiveness and its adaptability to evolving pressure and fluid distribution within the reservoir. Several lessons will be learnt from this first AICD pilot, particularly related to the criticality of fully integrated subsurface understanding, evaluation, and completion design studies. The use of AICD technology appears promising for retrofit solutions in high-GOR inactive strings, prolonging well life and increasing reserves. Regarding newly drilled wells, dedicated efforts are underway to associate this technology with enhanced reservoir evaluation methods, allowing to directly design the lower completion based on diagnosed reservoir heterogeneities. Reduced export pressure and artificial lift will feature in future field development phases, and offer the flexibility to extend the use of AICD's. The current technology evaluation phases are however crucial in the definition of such technology deployments and the confirmation of their long-term viability.

STUDY OF RESIDUAL SOIL SLOPE STABILITY WITH THE APPLICATION OF HORIZONTAL DRAINAGE

This study determines the effectiveness of horizontal drains on a slope which refers to a landslide at Putrajaya, Malaysia, in 2007. The incident buried 27 cars, and about 1200 people were transferred to a safe place. The main cause was identified as continuous and heavy rainfall. In Malaysia, abundant rainfall is common during the wet season. Therefore, one of the remedial measures to improve slope stability is applying horizontal drain to flush out rising groundwater and increase soil strength. In this study, the finite element method package, Plaxis, is used to analyze the slope stability changes in terms of the factor of safety (FOS). The simulation of slope behavior includes the horizontal drain conditions in lowering the groundwater level based on three parameters: the heights, appropriate depth, and inclination angle. The horizontal drains are installed at four different heights of 1 m, 2 m, 8 m, and 28 m from the toe of the slope. Based on the results, the horizontal drain is most efficient to be installed with 15 m long and zero degrees angle at the height of 1 m from the toe of the slope. At 2 m height, the drain should be installed with 26 m long and an angle of 1.8 degrees, and at 8 m height, the drain should be installed with 12 m long and an angle of 4.8 degrees. Moreover, at 28 m, the horizontal drain should be installed 20 m long and at an angle of 8.5 degrees. Therefore, this paper highlights the exceedingly appropriate design of horizontal drains at different heights, lengths, and tilt angles along the slope surface.

Conductor Sharing Drilling Technique

With the objective to drill two wells shared from one conductor with independent wellhead and completion, ADNOC Offshore drilling team pioneered for the first time in Umm Lulu field and ADNOC UAE the Conductor sharing drilling technique. Which is to drill two wells from one single conductor in wellhead tower. Well planning technique drilling 42" hole and run 36" conductor, then install lower male connector and run conductor Down Hole Guide (DHG) assembly to be a guide for both two wells. Land the DHG on the lower male connector. Install upper male connector, which is equipped with two well slots for drilling the two wells. Drilling 1st 16" hole and run 13 3/8" casing and cemented. Skid over second slot and drill second hole 16" and run and cement 13 3/8" casing and carry out top up cement job for both hole up to surface inside 36" conductor. Install casing head housing for each well. Then each well could be drilled as per normal procedures. Well executing process. Well challenges: Drilling large hole 42" hole with 42" bit and BHA. Run 36" conductor and conductor sharing DHG and keep aligned for accessibility of BHA and casing Nudge 16" hole for both two wells at centre-to-centre distance 8" safely without collision issue. Run two 13 3/8" casing strings in 36" conductor and cement same up to surface. Complete drilling well UL-056 from slot A, drilled 12 ¼" hole section to TH-I ABS, run 9 5/8" casing and perform cement job to surface, drilled 6" hole (linerless design) and land in TH II then continued drilling horizontal drain to TD, Run completion and deliver the well. Suspend the other well in slot B at 13 3/8" casing with securing the well with abandonment cap and as per ADNOC offshore policy.

Improving 4-1/2" Liner Deploy Ability in 6" Horizontal Hole with Utilization of Improved Characteristics Brines and Friction Reduction Devices

A large operator of a brown field offshore in the middle east has decided to provide full lower Completion accessibility and ensure prevention of open hole collapse as it can lead to various gains throughout the life of the well. Among those benefits, it provides a consolidated well bore for various production logging & stimulation tools to be deployed effectively, as well as full accessibility, conformance control and enable to provide production allocations for each zones. However there are multiple challenges in deploying lower completion liner in drains involving multiple reservoirs and geo steered wells: Well Bore Geometry, dog legs/ tortuosity etc. & differential sticking possibilities and of course the open hole friction. Due to the size of the open hole, restricted casing design and utilization of limited OD pipes further add to the complications of deploying the Lower completion liner in such brown Field wells. This paper intend to review the multi-step methodology approach implemented in recent years by the company to effectively deploy 4-1/2" Liner in 6" Horizontal Open Hole section. Among the techniques used to assist successful deployment of lower completions are: Improving hole cleaning, ensure smooth well bore with the use of directional drilling BHA, reduction of the Open Hole friction by utilizing Lubricated brines, fit for purpose Centralizers, use of drill pipe swivel devices to increase weight available to push the liner & reduce buckling tendency. With the length of open hole laterals reaching up to 10,000 ft for 6" Lower drains, open hole drag, friction & cleanliness are major components that causes challenges in deploying the Liner till TD. The use of specially formulated brines with fixed percentage of lubricants proved to significant reduce friction compared to the drilling mud used for drilling the horizontal drain. The combination of low friction brine with proper centralization / standoff which resulted in reduced contact area with the formation has also shown good results in preventing differentials sticking while running the liner through multilayer reservoirs having significantly different reservoir pressures. Another major constrain to deploy the lower completion liner in this offshore field is the very nature of the wells being primarily workover. This involves generally Tie back liners run to shallow depths to restore the integrity of wells. This limits our ability in the selection of drill pipe that can be used as only smaller OD drill pipes and HWDP can be utilized in order to deploy the Liner to bottom. On many occasions this provides only limited weight to push the Liner down to TD and impact our ability to set the liner top packer. Drill pipe rotating swivel devices have been utilized to improve our weight availability & transferability to push the liner down and to set the liner top packers. In order to provide independent deactivation mechanism for the drill pipe swivel and to have complete success in our liner deployments, a dedicated ball activated sub was designed to deactivate the swivel acting as back up in case primary deactivation methods fails during liner setting. The combined use of all these techniques enabled the company to deploy 4.5" Liners in 6" Horizontal drains with high success in this offshore Brown Oil field of UAE. This resulted in better well construction and complete access to lower drains over the life of the wells.

Pulling the Production: A New Way of Looking into Brown Field Reservoirs

One of the major brownfields in offshore India was producing for three decades from main carbonate reservoirs of the Eocene and Oligocene age. Average production of this brownfield is approximately 11,000 barrels of oil per day (BOPD). To maintain the declining reservoir pressure, the field has been under active water injection for more than two decades. However, being a complex carbonate reservoir with high textural heterogeneity, the water-front movement is not very well understood and monitored. To increase the oil production, the operator started drilling horizontal drain-holes from the platforms and has adopted a conventional perforated and blind tubing combination as a completion strategy. However, it was found that wells were performing poorly with very high water cut. An integrated and comprehensive petrophysical workflow was applied that used data analysis and the added value of advanced 3D acoustic data in combination with nuclear magnetic resonance (NMR) data to provide a rapid realistic solution to avoid such high watercut through optimizing the completion strategy. This led to a production gain in this offshore field, which was underperforming as per earlier predictions and expectations. Conventional well-log based qualitative evaluation for horizontal segmentation strategy was rejected in favor of an integrated approach for lateral reservoir facies delineation. Lateral petrophysical property characterization was carried out through quick integration of NMR pore-size driven facies analysis, advanced acoustic radial profiling, anisotropy, and Stoneley analysis. Permeability profiling along the horizontal drain-hole section using NMR and acoustics provided critical insight. Those were integrated to avoid potential high permeability conduits of thief zones for water breakthrough. A rock-quality index was derived to optimize the completion strategy soon after the logging, even preceding the rig-down of the acquisition runs and lowering of the completion. Zones with higher skin, deeper formation damage, and lower rock-mechanical properties were avoided for efficient swell-packer placements. The well started producing and continued production with only 10% water cut along with 450 barrels of oil compared to an average 90% watercut and 100 barrels of oil from the other wells of the same platform, which used the older nonoptimized completion strategy. Based on the promising result for the first well, the same workflow was used for two similar wells of other two different platforms inthe same field, which also resulted in similar production with enhanced oil production and reduced water cut. The study using the rapid integrated evaluation workflow established efficient zonal isolation of high permeability thief zones with accuracy for timely optimization of horizontal well segmentation, which assisted in pulling higher production in this brownfield by reducing unwanted water production.

Appraising the Development Potential of Ekofisk Over Tor Formation in the Halfdan Field, using a Multi-Disciplinary Approach to Well Planning and Applying Advances in Technology to Enhance Well Placement, Completion, Productivity and Recovery

Demonstrating a viable development for the Ekofisk reservoir directly above the producing Tor reservoir in the Halfdan Field (Danish North Sea) has historically been challenging. A recent well shows the value of cross-disciplinary collaboration and new technology to maximize recovery and mitigate reservoir and drilling risks. Specifically, 4D seismic was utilized when planning the well, while placement was optimized by using advanced geosteering tools. Well optimization was further enhanced by adopting novel completion and stimulation technologies. Pressure data and 4D seismic show that Tor and Ekofisk are in dynamic communication, but the degree of communication varies locally. The integration of 4D seismic with other disciplines’ input succeeded in optimizing the well placement and narrowed the significant pore pressure uncertainty along the 12,000-ft reservoir section. To maximize well length within the target zone and reduce the risk of being faulted out of the target reservoir deep resistivity was used to steer the well in the optimal layers. This contributed to 99% of the reservoir section being placed in the target zone. Lessons learnt from an earlier appraisal well and modest production experience in this part of the Ekofisk reservoir helped to justify the choice of selective completion zones (Sliding Side Door) in the inner part of the horizontal drain in order to minimize the impact of potential water or premature water breakthrough from high-rate injection wells located in the underlying Tor reservoir. This decision was validated after drilling the inner part of the well, where water-swept zones were encountered in the heel, followed by a long gas pay zone in line with 4D seismic signal in the remainder of the inner well section. To mitigate the risk of an unwanted fracture connection and increase contact with the tight oil-saturated reservoir, a novel stimulation and completion technology was successfully deployed in the outer 6-inch open-hole section of the well. The acid needles completion, deployed across a 3,000-ft reservoir interval and comprising 224 needles deployed by pumping acid, was the first installation of its kind in the Danish North Sea. For the acid needles completion, this installation holds two distinctions: the largest number of acid needles installed in a well, and the combination of the acid needles completion with a different completion system in a single lateral for the first time.

Setting a New Standard: PDC Bits Equipped with Compact Vibration Recorders Monitor Entire Run and Reveal Stick-Slip Mitigation System Dysfunction and Downhole Motor Under Performance

Downhole vibration measurements are used real-time and post-run to monitor drilling dynamics. Real-time monitoring tools are applied to facilitate immediate corrective actions but their deployment adds operational constraints and costs. This paper describes a new high-capability vibration recorder embedded in the drill bit as a standard component. The analysis of two case studies in the Middle East shows how memory devices available at a reduced cost and on every run are a valuable option for many appraisal or development wells.Developing a fleet of reliable downhole recording tools typically takes years and involves teams of experts in various fields. The paper describes the strategy followed by a drill bit manufacturer to develop and deploy a compact, high capability and cost-effective vibration recorder to provide continuous readings of accelerations, rotation speed (RPM) and temperature at 100Hz and over 250 hours. Sensors and batteries have been packaged to fit into the drill bit shank or elsewhere in the bottom hole assembly (BHA). The recording starts automatically and thus removes the need for onsite personnel. The paper also presents proprietary data analytics software used to retrieve, process and synchronize the recorded data with other available data (mud logs, Measurement/Logging While Drilling logs) and to present critical drilling events.In the first application, the 8 ½-in. bit drilled a 20,000 ft horizontal drain. More than 250 hr of data were recorded showing intense levels of stick-slip. During the entire run, the drilling team deployed several strategies to mitigate stick-slip, including the use of two surface-based stick-slip mitigation systems. The analysis shows that these systems are sometimes unsuccessful in mitigating stick-slip and are difficult to calibrate. It is demonstrated how the vibration recorder may contribute to fine tuning these mitigation efforts through optimization of their settings. In the second application, the vibration recorder was mounted on a 12 1/4-in. bit used to drill 5,000 ft through cement and formation. The analysis shows the motor was subjected to erratic RPM cycles, leading to frequent stalls and acceleration peaks during the run. It is shown how motor performance then decreased consistently during the last hundreds of feet of the section and how this affected rate of penetration (ROP).Deployment of a vibration recorder over the entire drill bit manufacturer's fleet allows continuous monitoring of critical drilling issues and malfunctions related to a variety of drilling equipment that enables the operator to improve drilling performance. The bit-sensor package makes high frequency data systematically available at a reduced cost for every drilling application.