horizontal section
Recently Published Documents

Abstract The opportunity to refracture low-producing horizontal wells, which have been fractured few months before is getting more and more popular in the last few years. It provides the opportunity of restoring production without drilling new wells, which might be economically feasible especially in the oil and gas low price environment. However, the success rate of refracturing operations is usually low, mainly driven by the inability to properly stimulate the entire horizontal section. Consequently, many operators do not widely deploy this efficient technology. In contrast, completing a newly drilled well with plug and perf technology allows to individually treat from forty to sixty or even more individual compartments in the lateral section while refracturing attempts to retreat the entire lateral in the absence of any isolating device while trying to cover the entire lateral. There are at least two key factors affecting this operation. First is diversion technology: without efficient chemical diverters, which allow to temporarily block recently treated intervals and divert the stimulation fluid to different open sections of the well is extremely challenging. These diverters should normally be able to hold pressure differentials up to thousand psi or more. Attempting a treatment without this technology, aka a "blind frac" is not an option in many cases. The second factor is monitoring technology: The ability to recognize whether a zone has been successfully stimulated, to decide on the deployment of diverting technology or the further addition of stimulation fluid, to sponsor lateral coverage with minimal risk of premature screen out becomes of utmost importance for the successful outcome of hydraulic refracturing operations. In the absence of either of the aforementioned factors hydraulic refracturing may become inefficient and yield uneconomic success. This paper presents how the application of novel diverters, combined with proper hydraulic fracturing fluid selection, sound engineering design and more importantly hydraulic fracturing monitoring provide a new opportunity for the deployment of hydraulic refracturing to provide significant production increase and enhance recovery factor.

Abstract The carbonate reservoir S is a giant limestone reservoir in H Oilfield, Iraq. Although the reserves account for 25%, the production contribution is only 0.4% to the total oilfield production due to poor petrophysical properties. Accordingly, the first proppant fracturing on vertical well was successfully executed in December 2016, which has already achieved a steady production period over than 3 years. In order to further improve the productivity, the first multi-stage proppant fracturing(MSPF) on horizontal well(SH01X) was successfully applied in November 2019, a technique which is rarely reported for porous limestone reservoir in the Middle East. Proppant fracturing in carbonate reservoirs is a technique difficulty worldwide, especially this is a lack of experiences in the Middle East. To ensure the success of this campaign, a holistic technical study including geology evaluation, reservoir performance analysis, drilling trajectory design, completion and fracturing technique design have been carried out based on principle of "geology-engineering integration". This paper will present a comprehensive illustration including treatment design (main completion-fracturing technique, total scale, fracturing fluid, proppant), job execution (mini-frac, main-frac) and post-frac production performance for this successful campaign. True vertical depth (TVD) of Well SH01X is 2720 m and the horizontal section length is 811 m. Based on the main technique of multi-stage proppant fracturing with open hole packers and sliding sleeves, totally 3784.3 m3 fracturing fluid and 452 m3 proppant were pumped in 8 stages. The test production was 3214 BOPD (choke size: 40/64", wellhead pressure: 970 psi). A historical breakthrough in the productivity of S reservoir has been achieved by the campaign. The post-frac evaluation shows that the treatment parameters are consistent with the design. The connectivity between artificial fractures and formation is greatly improved, and the stimulation effect is significant. Currently the "production under controlled pressure" mode has been executed and the stable production under stimulation target rate has been maintained. The systematic "geology-engineering integration" workflow is of significance to the success of the treatment as well as the stimulation effect. MSPF is planned to be a game-changing technique to develop the huge reserves of S reservoir. The experience gained from this case could provide theoretical as well as practical references for similar reservoirs in the Middle East.

This paper reports the theoretical findings of the new modified type of tuned liquid column ball damper (TLCBD), called a tuned liquid column ball spring damper (TLCBSD). In this new modified form, the ball inside the horizontal section of the damper is attached to the spring. Furthermore, two types of this modified version are proposed, known as a tuned liquid column ball spring sliding damper (TLCBSSD) and a tuned liquid column ball spring rolling damper (TLCBSRD). In the former, the rotational motion of the ball attached to the spring is restricted, whereas in the latter, the ball attached to the spring can translate as well as rotate. Mathematical models and optimum design parameters are formulated for both types. The performance of these new modified damper versions is assessed numerically and subjected to harmonic, seismic, and impulse loadings. The results show that the performance of the newly proposed dampers is relatively better than traditional TLCBDs in harmonic and seismic excitations. The peak response reduction soon after the impact load becomes zero is comparatively better in TLCBSDs over TLCBDs. Overall, the newly proposed passive vibration control devices performed excellently in structure response reduction over TLCBDs.

Abstract In the increasingly complex and cost sensitive drilling environment of today, data gathered using downhole and surface real-time sensor systems must work in unison with physics-based models to facilitate early indication of drilling hazards, allowing timely action and mitigation. Identification of opportunities for reduction of invisible lost time (ILT) is similarly critical. Many similar systems gather and analyze either surface or downhole data on a standalone basis but lack the integrated approach towards using the data in a holistic decision-making manner. These systems can either paint an incomplete picture of prevailing drilling conditions or fail to ensure system messages result in parameter changes at rigsite. This often results in a hit or miss approach in identification and mitigation of drilling problems. The automated software system architecture is described, detailing the physics-based models which are deployed in real-time consuming surface and downhole sensor data and outputting continuous, operationally relevant simulation results. Measured data from either surface, for torque & drag, or downhole for ECD & ESD is then automatically compared both for deviation of actual-to-plan, and for infringement of boundary conditions such as formation pressure regime. The system is also equipped to model off-bottom induced pressures; swab & surge, and dynamically advise on safe, but optimum tripping velocities for the operation at hand. This has dual benefits; both the avoidance of costly NPT associated with swab & surge, as well as being able to visually highlight running speed ILT. All processing applications are coupled with highly intuitive user interfaces. Three successful deployments all onshore in the Middle East are detailed. First a horizontal section where real-time model vs. actual automatic comparison of torque & drag samples, validated with PWD data allowed early identification of poor hole cleaning. Secondly, a vertical section where again the model vs. actual algorithmic automatically identified inadequate hole cleaning in a case where conventional human monitoring did not. Finally, a case is exhibited where real-time modelling of swab and surge, as well as intuitive visualization of the trip speeds within those boundary conditions led to a significant increase in average tripping speeds when compared to offset wells, reducing AFE for the operator. Common for all three deployments was an integrated well services approach, with a single service company providing the majority of services for well construction, as well as an overarching remote operations team who were primary users of the software solutions deployed.

Abstract Objectives/Scope Controlling the excessive water production from the high water cut gravel packing horizontal well is a challenge. The approach which uses regular packers or packers with ICD screens to control the unwanted water does not function well. This is mainly because of the length limitation of packers which will make the axial flow resistance insufficient. Methods, Procedures, Process In this paper, a successful case that unwanted water is shutoff by using continuous pack-off particles with ICD screens (CPI) in the whole horizontal section in an offshore oilfield of Bohai bay is presented. The reservoir of this case is the bottom-water high viscosity reservoir. The process is to run 2 3/8" ICD screen string into the 4" screen string originally in place, then to pump the pack-off particles into the annulus between the two screens, and finally form the 360m tightly compacted continuous pack-off particle ring. Results, Observations, Conclusions The methodology behind the process is that the 2-3/8" ICD screens limit the flow rate into the pipes as well as the continuous pack-off particle ring together with the gravel ring outside the original 4" screens to prevent the water channeling into the oil zone along the horizontal section. This is the first time this process is applied in a high water cut gravel packed horizontal well. After the treatment, the water rate decreased from 6856BPD to 836.6BPD, the oil rate increased from 44BPD to 276.8BPD. In addition, the duration of this performance continued a half year until March 21, 2020. Novel/Additive Information The key of this technology is to control the unwanted water by using the continuous pack-off particles instead of the parkers, which will bring 5 advantages, a) higher efficiency in utilizing the production interval; b) no need to find the water source and then fix it; c) the better ability to limit the axial flow; d) effective to multi-WBT (water break though) points and potential WBT points; e) more flexible for further workover. The technology of this successful water preventing case can be reference to other similar high water cut gravel packed wells. Also, it has been proved that the well completion approach of using CPI can have good water shutoff and oil incremental result. Considering the experiences of historical applications, CPI which features good sand control, water shutoff and anti-clogging is a big progress compared to the current completion technologies.

Abstract Hydraulic fracturing is a well stimulation treatment that has been around since the 1940s, becoming more popular in recent years because of the unconventional hydraulic fracturing boom in North America. Between the 1990s and 2000s, the oil and gas industry found an effective way to extract hydrocarbons from formations that were previously uneconomical to produce. Consolidated unconventional formations such as shale and other tight rocks can now be artificially fractured to induce connectivity among the pores containing hydrocarbons, enabling them to easily flow into the wellbore for recovery at the surface. The method of fracturing unconventional reservoirs requires a large amount of surface equipment, continuously working to stimulate the multiple stages perforated along the horizontal section of the shale formation. The operations normally happen on a single or multi-wells pad with several sets of perforations fractured by using the zipper-fracturing methodology (Sierra & Mayerhofer, 2014). Compared with conventional hydraulic fracturing, the surface equipment must perform for extended pump time periods with only short stops for maintenance and replacement of damaged components. This paper addresses improvements made to the fracturing fluid delivery systems as an alternative to the fracturing iron traditionally used in fracture stimulation services. The improvement aims to enhance equipment reliability and simplify surface setup while reducing surface friction pressure during the hydraulic fracturing treatment.

Abstract Several techniques have been applied to improve the water conformance of injection wells to eventually improve field oil recovery. Standalone Passive flow control devices or these devices combined with Sliding sleeves have been successful to improve the conformance in the wells, however, they may fail to provide the required performance in the reservoirs with complex/dynamic properties including propagating/dilating fractures or faults and may also require intervention. This is mainly because the continuously increasing contrast in the injectivity of a section with the feature compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone which ultimately creates short-circuit to the nearby producer wells. The new autonomous injection device overcomes this issue by selectively choking the injection of fluid into the growing fractures crossing the well. Once a predefined upper flowrate limit is reached at the zone, the valves autonomously close. Well A has been injecting water into reservoir B for several years. It has been recognised from the surveys that the well passes through two major faults and the other two features/fractures with huge uncertainty around their properties. The use of the autonomous valve was considered the best solution to control the water conformance in this well. The device initially operates as a normal passive outflow control valve, and if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This provides the advantage of controlling the faults and fractures in case they were highly conductive as compared to other sections of the well and also once these zones are closed, the device enables the fluid to be distributed to other sections of the well, thereby improving the overall injection conformance. A comprehensive study was performed to change the existing dual completion to a single completion and determine the optimum completion design for delivering the targeted rate for the well while taking into account the huge uncertainty around the faults and features properties. The retrofitted completion including 9 joints with Autonomous valves and 5 joints with Bypass ICD valves were installed in the horizontal section of the well in six compartments separated with five swell packers. The completion was installed in mid-2020 and the well has been on the injection since September 2020. The well performance outcomes show that new completion has successfully delivered the target rate. Also, the data from a PLT survey performed in Feb 2021 shows that the valves have successfully minimised the outflow toward the faults and fractures. This allows achieving the optimised well performance autonomously as the impacts of thief zones on the injected fluid conformance is mitigated and a balanced-prescribed injection distribution is maintained. This paper presents the results from one of the early installations of the valves in a water injection well in the Middle East for ADNOC onshore. The paper discusses the applied completion design workflow as well as some field performance and PLT data.

Abstract Over the past decade, coiled tubing (CT) has been one of the preferred fluid conveyance techniques in tight carbonate oil producers completed with an uncased horizontal section. In the onshore Middle East, conventional CT stimulation practices have delivered inconsistent results in that work environment. This is mainly due to a mix of reservoir heterogeneity, limited CT reach, lower CT pumping rates, uncontrolled fluid placement, and uncertainty of downhole dynamics during the stimulation operations. An intervention workflow recently validated in onshore Middle East to acidize tight carbonate openhole horizontal water injectors was introduced for the first time in an oil producer. The advanced stimulation methodology relies on CT equipped with fiber optics to visualize original fluid coverage across the openhole interval through distributed temperature sensing (DTS). Real-time downhole telemetry is used to control actuation of CT toolstring components and to understand changing downhole conditions. Based on the prestimulation DTS survey, the open hole is segmented into sections requiring different levels of stimulation, fluid placement techniques, and diversion requirements. The candidate carbonate oil producer featured an average permeability of 1.5 md along 8,003 ft of 6-in. uncased horizontal section. Because of the horizontal drain's extended length and the presence of a minimum restriction of 2.365-in in the 3 1/2-in. production tubing, a newly developed CT slim tractor was essential to overcome reach limitations. In addition, a customized drop-ball high-pressure jetting nozzle was coupled to the extended reach assembly to enable high-energy, pinpoint acidizing in the same run. The instrumented CT was initially run until lockup depth, covering only 53% of the horizontal section. The CT slim tractor was then precisely controlled by leveraging real-time downhole force readings, enabling full reach across the open hole. Prestimulation DTS allowed identification of high- and low-intake zones, which enabled informed adjustments of the acidizing schedule, and in particular the level of jetting required in each section. After its actuation via drop-ball, the high-pressure jetting nozzle was operated using downhole pressure readings to ensure optimum jetting conditions and avoid exceeding the fracturing threshold. Upon completion of the stimulation stage, post-stimulation DTS provided an evaluation of the fluid placement effectiveness. After several weeks of production, the oil rate still exceeded the operator's expectations fivefold. This intervention validates the applicability of the advanced matrix stimulation workflow in tight carbonate oil producers completed across a long openhole horizontal interval. It also confirms the value of real-time downhole telemetry for optimal operation of extended reach toolstrings and the understanding of the downhole dynamics throughout stimulation treatments, the combination of which ultimately delivers breakthrough production improvements compared to conventional stimulation approaches, in a sustainable manner.

Abstract In high-temperature carbonate producers, conventional hydrochloric (HCl) acid systems have been ineffective at delivering sustainable production improvement due to their kinetics. Retarded acids are deemed necessary to control the reaction and create effective wormholes. This scenario is even more critical in wells completed across long openhole horizontal intervals due to reservoir heterogeneity, changing downhole dynamics, and uniform acid placement goals. Out of the different retarded acid options, emulsified acid is one of the preferred choices by Middle East operators because of its excellent corrosion inhibition and deep wormhole penetration properties. However, it also brings other operational complexities, such as higher friction pressures, reduced pump rates, and more elaborate mixing procedures, which in some cases restrict its applicability. The recent introduction of a single-phase retarded inorganic acid system (SPRIAS) has enabled stimulation with the same benefits as emulsified acids while eliminating its drawbacks, allowing friction pressures like that of straight HCl and wormholing performance equivalent to that of emulsified acid. A newly drilled oil producer in one of the largest carbonate fields in onshore Middle East was selected by the operator for pilot implementation of the SPRIAS as an alternative to emulsified acid. The candidate well featured significant damage associated with drilling, severely affecting its productivity. The well was completed across 3,067 ft of 6-in. openhole horizontal section, with a bottomhole temperature of 285°F, permeability range of 0.5 to 1.0 md, and an average porosity of 15%. Coiled tubing (CT) equipped with fiber optics was selected as the fluid conveyance method due to its capacity to enable visualization of the original fluid coverage through distributed temperature sensing (DTS), thus allowing informed adjustment of the stimulation schedule as well as identification of chemical diversion and complementary fluid placement requirements. Likewise, lower CT friction pressures from SPRIAS enabled the utilization of high-pressure jetting nozzle for enhanced acid placement, which was nearly impossible with emulsified acid. Following the acidizing treatment, post-stimulation DTS showed a more uniform intake profile across the uncased section; during well testing operations, the oil production doubled, exceeding the initial expectations. The SPRIAS allowed a 40% reduction in CT friction pressures compared to emulsified acid, 20% optimization in stimulation fluids volume, and reduced mixing time by 18 hours. The experience gained with this pilot well confirmed the SPRIAS as a reliable option to replace emulsified acids in the region. In addition to production enhancement, this novel fluid simplified logistics by eliminating diesel transportation, thus reducing equipment and environmental footprints. It also reduces friction, thus enabling high-pressure jetting via CT, leading to more efficient stimulation with lower volumes.