A Solution to Sand Production from Natural Gas Hydrate Deposits with Radial Wells: Combined Gravel Packing and Sand Screen

Sand production is one of the main problems restricting the safe, efficient and sustainable exploitation of marine natural gas hydrate. To explore the sand-control effects of gravel packing, experiments that simulate hydrate extraction in the water-rich environment were conducted with designed hydrate synthesis and exploitation devices. Three sand control completion methods, including 120 mesh sand screen, 400 mesh sand screen, 120 mesh sand screen combined with gravel packing, are adopted. Sand and gas production rates were compared under different well types and sand control completion methods. Results show that the gas production modes of radial wells and vertical wells are almost the same at the same time due to the small experimental scale and high permeability. The sand production of the vertical well with gravel packing combined with a sand-control screen is 50% lower than that of the vertical well with sand-control screens only. Radial well with gravel packing combined with sand-control screens produced 87% less sand than screen mesh alone. The cumulative gas production and recovery rates of a radial well with the composite sand control method are better than those without gravel packing in the same development time.

Analysis of Shunted Screen Gravel Pack Process and Calculation of Friction in Deepwater Horizontal Wells

Shunted screen gravel packing is a kind of technology which is difficult to complete gravel packing with the conventional method in low fracture pressure formation and long wellbore length condition. According to the characteristics of LS 17-2 deepwater gas field, the shunted screen packing tool was designed and the gravel packing process and packing mechanism were analyzed. The variation law of the flow friction, flow rate distribution in multichannel, and other parameters of the shunted screen gravel packing were analyzed and calculated. The friction calculation model of different stages of gravel packing was established. A gravel packing simulation software was developed to simulate the friction in different stages of shunted screen gravel packing. The parameters such as sand-dune ratio, pumping sand amount, packing length, and packing time in the process of packing were also calculated. In deepwater horizontal well gravel packing, the results show that the friction ratio of the string is the largest in the stage of injection and α-wave packing. While the friction increases rapidly in the stage of β-wave packing because the carrier fluid needs to flow through the long and narrow washpipe/screen annulus. Particularly when the β-wave packing is near the beginning of the open hole, the packing pressure reaches the maximum. The calculated results are in good agreement with the measured results of the downhole pressure gauge. The model and software can provide technical support for the prediction and optimization of gravel packing parameters in the future.

An Industry First: Concept Selection, Material Testing, and Modelling Process for a Successful Managed Pressure Open Hole Gravel Pack Project

One of the major technical challenges to this project was placing horizontal open hole gravel packs (HzOHGP) within the narrow pore pressure to frac-gradient (PPFG) margin in the target reservoirs. This paper addresses the steps taken to overcome this challenge. To maximize the use of the narrow PPFG margin, the project combined a managed pressure drilling (MPD) system with low gravel placement pump rates made possible by an ultra-light-weight proppant (ULWP). Of the MPD systems available, the Controlled Mud Level (CML) system was selected over the Surface Back Pressure (SBP) system for several reasons. It enabled conventional gravel pack pumping operations and equipment and it accommodated the brine weight needed to inhibit the shales. A series of lab tests showed that the completion fluid density required to inhibit the reservoir shale reactivity was only possible using CML. An overall evaluation of CML showed that it was most suitable and offered the greatest flexibility for the gravel pack job design. The special ceramic ULWP had to be qualified and tested. The qualification testing ranged from standard API and compatibility tests to full scale flow loop testing. The flow loop tests were needed to measure the ULWP transport velocity for the target wellbore geometry. Understanding the transport velocity is critical for gravel pack design and job execution planning. Once MPD and ceramic ULWP were selected, the gravel pack placement operations were simulated to demonstrate that their features increased the likelihood of successfully gravel packing in the target reservoirs. Small PPFG margins decrease the probability of success of placing a HzOHGP. In the target formations, the pressure margin is insufficient to safely execute HzOHGP conventionally; instead, the project combined MPD and the low pump rates facilitated by using ULWP to control circulating pressures to stay inside the narrow margin and place the gravel packs. The integration of CML and ULWP into in a gravel pack operation to control circulating pressures has never been done. The concept and its successful field implementation are industry firsts.

High Density Gravel Packing Fluid for High-Temperature Deep Water Wells

Southeast offshore India reservoirs have high-temperature deep water wells with significantly high pressures and unconsolidated sandstone formations. Controlling sand production is a major issue from inception to well completion and throughout the life of the well. A high density brine is required due to the high bottom hole pressures, thus executing sand control operations using such a high density brine as the base fluid for the gravel pack carrier fluid combined with the elevated temperatures is a significant challenge. A case is presented where a high-density temperature-resistant gravel packing fluid was optimized for a BHT of 320°F using a high-density brine. Additionally, the pH of the fluid was crucial considering the significant presence of CO2 in the formation, which was anticipated to affect asset integrity due to corrosion at low pH. A biopolymer-based fluid with oxidizing breaker was required in 14.2 ppg potassium-cesium formate brine and 12.5 ppg potassium formate brine. The fluid required evaluation for rheology and stability at 320°F, and at a shear rate of 170 s-1 with two conditions of viscosity to be sustained in the range of 75- 150 cP and 150-250 cP for the initial four-hour duration. The same fluid, after four hours, was also required to be broken within fourteen days. The fluid with the optimized formulation in regard with stability and rheology was further required to pass an acceptable sand suspension of ≤ 5% settling. Finally, the optimized fluid was required to show negligible corrosion effects on the downhole metallurgies. The stability and rheology were studied using a HPHT concentric cylinder viscometer. The sand suspension and corrosion characteristics were studied using an HPHT autoclave. The same fluid was studied with an acid breaker as a contingency for wells without CO2-related issues. After an extensive study, 12.72 gal/Mgal liquid gel concentrate of biopolymer when hydrated in 14.2 ppg and 15.45 gal/Mgal liquid gel concentrate of biopolymer, when hydrated in 12.5 ppg, providing viscosity in the range of 150-250 cP with 3 gal/Mgal and 5 gal/Mgal oxidizing breaker were selected, respectively. The optimized formulations passed sand suspension and had a pH in the range of 8-10, which imparted negligible corrosion loss to chrome- and nickel-based metallurgies. At the same conditions, the fluid showed acceptable results with 20 gal/Mgal organic acid breaker where the pH was ≤ 7. The combination of a commonly used biopolymer and a mixed formate brine produced a thermally stable fluid with unconventional chemistry, applicable for high-temperature, high-density conditions. With further study, it is expected that the temperature limit of this fluid can be extended beyond 320°F. The formulation for potassium formate brine was also tested at using field scale equipment to check for ease of mixing, reproducibility of results and for determining friction values when pumped at a certain rate via shunts. The fluid was mixed with relative ease using standard batch mixers and replicated the properties that were determined on a lab scale. The fluid also depicted superior proppant carrying capacities and lower friction numbers than expected which would enable lowering of overall surface pressures and surface pumping requirements.

Autonomous Inflow-Control Devices Boost Production While Managing Sand

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30403, “Sand Production Management While Increasing Oil Production of a Gravel-Packed Well Equipped With Rate-Controlled-Production Autonomous Inflow-Control Devices in a Thin Heavy-Oil Reservoir Offshore China,” by Shuquan Xiong, Fan Li, and Congda Wei, CNOOC, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. A 2018 infill development campaign for a horizontal well offshore China targeted improved production through the installation of autonomous inflow-control devices (AICDs). However, because the well requires gravel packing to manage the sand, the integration of AICDs and the gravel pack was an issue. An integrated work flow was followed to deliver the AICD application successfully in an offshore heavy-oil reservoir with major uncertainties in remaining oil thickness and water/oil contacts. AICD completions ensured balanced contribution from all reservoir sections and limited water production significantly while the gravel pack kept the valves safe from the effects of sand. Field Description The field is a low-amplitude fault anticline oil field developed on the basement uplift. The structure is relatively gentle (Fig. 1). The reservoir lithology is mainly feldspathic quartz sandstone, with an average porosity of 22%, an average permeability of 397 md, a reservoir pressure coefficient of 1, an oil density of 0.92 g/cm3, and crude oil viscosity of 150 cp. The current methodology for gravel packing with ICDs/AICDs in the well uses a multiple alpha-wave technique whereby at least one conventional standalone screen joint is deployed at the toe of the well to provide a return path during the buildup of the alpha wave. The flow rate is reduced progressively to maximize the dune weight until screenout is observed. Once the gravel-packing operation is complete, the standalone-screen section at the toe is isolated before the well is placed on production. This technique does not allow a complete pack to be achieved and will allow more gravel to build up around the zonal isolation packers. This methodology is most applicable in unconsolidated sands with high net-to-gross reservoirs where borehole collapse will occur early in well life. One technique to provide sufficient flow path through the screen assembly is to integrate sliding sleeves into each screen joint. However, in long lateral wellbores, this may be prohibitively expensive and requires multiple manual manipulations as the wash pipe is retrieved. The use of a temporary bypass valve is recommended to enable standard gravel-packing operations to be performed with ICDs without significant additional cost, complexity, or compromise. The dissolvable material is used with a valve located within the ICD/AICD housing to provide a high-flow-area path from the annulus to the tubing during completion operations.

Understanding AICD Gravel Packing

In recent years, it has become common practice for operating companies to make a significant effort in the planning of gravel pack installations, especially in their most important wells. Typically, the placement of the gravel pack is accurately modelled, and multiple contingencies developed for potential alternative scenarios to reduce the overall risk of execution. After the pack has been placed, the use of down-hole gauge data enables the gravel pack to be fully evaluated in order to confirm success and investigate any issues or failures. This understanding feeds into improved designs and ever higher success rates for future completions. The most challenging gravel packs Operators are installing today are those placed in long horizontal open holes, around screens fitted with Inflow Control Devices (ICDs) or Autonomous Inflow Control Devices (AICDs). Simulating gravel pack placement in wells such as these requires the effective modelling of unusually dynamic and complex flow paths. Until recently, no simulator could adequately model these treatments. Most jobs have also been done without the downhole gauges necessary for a complete job evaluation, which has resulted in a lack of data for job evaluation and understanding. Consequently, completions requiring the pack to be placed around ICD/AICD screen assemblies have, until recently, been done without the assurance of pre-job gravel pack placement modelling. The lack of an adequate simulator has also meant that, even on these complex and valuable wells, Operators have been restricted to simple volumetric evaluation of their success. With no way to understand actual packing mechanisms or investigate root causes of failures, the assumptions made on how packing occurs in these complex wells have remained unconfirmed. Recent evolution of gravel pack simulators has made the effective pre-job simulation, and post-job evaluation, of gravel packs placed around ICD/AICDs a reality. This paper presents the results of the first evaluation of a multi-proppant deep water horizontal alpha beta gravel pack around AICD screens. It facilitates the understanding of how such gravel packs are placed, validates the packing efficiencies, and illustrates the benefits of using multiple gravels for packing.

Nanomaterials Improve Polymer-Based Gravel-Packing Fluids at High Temperature

A gravel packing fluid system was developed for elevated temperature applications above 290°F comprised of xanthan gum and a high-temperature gravel suspension additive. This fluid system has been successfully pumped in four openhole gravel packing operations so far, validating its suitability for Alternate Path gravel packing technology involving shunt tubes. Laboratory qualification testing for this fluid showed excellent gravel suspension, rheology, and breaking profiles for cleanup and minimal damage during production. Xanthan gels have been used in gravel packing applications for many years. However, by itself, xanthan was unable to suspend gravel at temperatures above 290°F possibly due to onset of thermally activated polymer degradation. This paper demonstrates that gravel suspension ability can be vastly improved with the addition of a recently developed nano-additive. This additive is a specially designed versatile nanosized material that has a proven track record with visco-elastic surfactant fluids in the past. In the present study, we show the successful application of this additive with polymer-based carrier fluids such as xanthan, effectively increasing their application range to 325°F. With the inclusion of this suspension additive, xanthan concentration in the fluid system can also be reduced, which has other potential benefits such as better cleanup after gel break. Extensive laboratory evaluation for fluid qualification was performed prior to the job. High-pressure/high-temperature (HP/HT) rheology measurements were performed using industry-standard rheometers at various shear rates to match specific viscosity requirements for shunt tube applications. Gravel suspension tests performed using special pressurized cells immersed in oil bath at the required bottomhole static temperature showed improved gravel suspension with the nano-additive. Fluid breaking with conventional oxidative breaker was also demonstrated with viscosity measurements. Formation response tests showed very good fluid cleanup with 90% regained permeability. Laboratory testing and successful field applications have proven the effectiveness of this new fluid system.

Study for gravel slection and pack operation for oil production well on Song Doc oil field

Sand control by gravel packing is by far the most reliable and effective sand control method and is being used worldwide. One of the most important factor for successful operation is gravel size selection which is suitable with properties of well and particle size of sand from the reservoir, also the operation method needs to be considered during study. Due to the variety of different oilfield, the selections of gravel size and operation method are challenges for petroleum engineer and manager. Oil production wells in Song Doc oil field are producing in Miocene and Oligocene with very high rate of sand production; some of the wells were plugged by sand. Therefore, the study on the selections of gravel size and operation method is needed and important. In this study, theory analyzing was used in order to yield advantage and disadvantage of each gravel packing method and their operation. Based on the operating condition on Song Doc field and the availability of equipment on site, gravel packing method by thru-tubing with vent screen was selected. The coil tubing was chosen as the operation method. This is the best sand control method for the Song Doc oil field with low cost and high effectiveness sand control.