Jia, Hu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation at Southwest Petroleum University) | Chen, Hao (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation at Southwest Petroleum University)
Using mature Cr3+/partially hydrolyzed polyacrylamide (HPAM) gel can reduce filtration for water shutoff in the fractured reservoir. Whether the mature gel can act as a fluid-loss-control pill for well-workover operation is worth investigating. In this paper, we start a systematic experimental study to reveal the physical process and fluid-loss-control mechanism of the Cr3+/KYPAM (salt-tolerant polymer) gel used for overbalanced well workover. The polymer gel used in this study is formulated with a combination of 0.4 to 0.6 wt% KYPAM and added 0.02 to 0.04 wt% chromium acetate, which can provide a gelation time between 2 and 4 hours, and with a maximum gel strength of Code G at a temperature of 30°C. Results show that the mature Cr3+/KYPAM gel can withstand positive pressure of 10 MPa for a period of 120 minutes with average fluid-loss volume of 15 cm3 for the core permeability between 9.18 and 217 md, indicating a favorable fluid-loss-control performance. The regained-permeability recovery can reach up to 85% for different core permeabilities. Scanning-electron-microscope (SEM) pictures show that a dense structure was formed in the gel filter cake during fluid-loss experiment. The wettability results show that the core has a greater potential to increase its water-wet ability after interacting with Cr3+/KYPAM mature gel. Field test shows that a small amount of gel leakoff was observed during each reperforation process, whereas water cut decreased from 89.1 to 52.1% and oil production increased from 0.15 to 1.11 m3/d. This study suggests that the mature Cr3+/KYPAM gel can act as a fluid-loss-control pill in high-water-cut oil wells, which can provide an avenue to bridge the design philosophy of well workover and water shutoff.
López, Byron (Sertecpet S.A.) | Córdova, Freddy (Sertecpet S.A.) | Mena, Leonardo (Sertecpet S.A.) | Soria, Jorge (Sertecpet S.A.) | Llori, Cesar (Sertecpet S.A.) | Melo, Vinicio (National Polytechnic School of Ecuador)
The objective of this paper is to present the development and application of a tool to repair holes in oilwell production tubing, using a method that does not require rig and wireline operations to locate the depth of the hole. The tool locates the leak and repairs it in a single run, reducing the time required to re-establish well production. This article describes the operational mechanism of the tool and its installation process. Two repairs were performed in oil wells, one of which sealed a hole near the bottom of the tubing and the second of which sealed a hole near the surface. The holes were sealed in a fraction of the time required by current solutions. This newly developed tool is a cost-effective alternative for resolving oilwell-integrity problems.
Fracture conductivity in shale formations can be greatly reduced because of water/rock interactions depending on the properties of formation rock and reservoir/fracture fluids. The mechanisms of water damage to fracture conductivity include clay swelling, surface softening, excessive proppant embedment, and fines migration caused by fracture-surface spalling and failed proppant particles. Fracture conductivity is influenced by closure stress, bulk and surface rock mechanical properties, fracture-surface topography, fracture-surface elemental composition, rock mineralogy, and proppant type and concentration, among other factors. This paper presents a study considering several of the aforementioned factors, centered primarily on saline-water-induced fracture-conductivity impairment of the Eagle Ford Shale Formation and its five vertical lithostratigraphic units.
Laboratory experiments were conducted to investigate and quantify the effect of flowback water on fracture conductivity for samples of Eagle Ford Shale. The majority of test samples were obtained from an outcrop in Antonio Creek, Terrell County, Texas, while the remaining samples were obtained from downhole core provided by an industry partner. The different lithostratigraphic units present in the Eagle Ford Shale formation were accounted for. Saline water with a chemical composition similar to that of the typical field flowback water was used.
Fracture-conductivity measurements were conducted in three stages. In the first stage, dry nitrogen was flowed to ascertain the undamaged initial fracture conductivity. In the second stage, the saline solution was injected into the fracture until steady-state behavior was observed. In the third and final stage, dry nitrogen was once again flowed to quantify the recovered fracture conductivity. Reported mechanical properties from the same outcrop-rock samples, consisting of Poisson’s ratio and the Brinell hardness number (BHN), were considered in this study. In addition, reported mineralogy obtained by use of X-ray-diffraction (XRD) microscopy was taken into consideration. The elemental composition along the fracture surface was obtained by use of X-ray-fluorescence (XRF) microscopy, and fracture-surface topography was obtained by use of a laser surface scanner and profilometer.
Results support findings that bulk and surface mechanical properties influence fracture conductivity, as well as surface topography and related attributes such as fracture surface area. Furthermore, the bulk mineralogical composition of the rock and the elemental composition of the rock fracture surface have a significant effect on fracture conductivity when flowing saline water to simulate flowback. Clay content was observed to directly influence fracture conductivity. The results of this study show a loss of fracture conductivity for the Eagle Ford Formation ranging from approximately 4 to 25% after flowing saline water, compared with the initial conductivity measured by flowing dry nitrogen before saline-water exposure. This is not a large loss in conductivity caused by water damage, and suggests that water damage may not be the major cause of the large early decline rates observed in most Eagle Ford Shale producing wells.
In this study, a gas/liquid flow has been numerically investigated in a rotary gas separator (RGS) to improve the performance of the RGS. One-phase flow and then two-phase flow were analyzed in an inducer, which is the main component of the RGS. A parametric study showed that reduced blade thickness and a higher number of blades increased the inducer’s head. However, an inducer with two blades generated greater head. Higher inlet-flow temperature (by inlet preheating) improved operation conditions, especially in lower flows. In addition, smaller bubble sizes led to a lower head. Alternately, the changes are not significant, and results are close and similar in smaller sizes. In the next step, the performance of the designed RGS was analyzed by computational fluid dynamics (CFD) and validated with available experimental data. Then, the effect of the quantity of the gas-output ports on the RGS’s efficiency was studied. As a result, the system with four ports was suggested as optimal. Moreover, results showed that increasing the length of the separator zone leads to increasing the efficiency until reaching an optimal length equal to the length of the inducer zone. Finally, the effect of the blade number was studied for various rated points.
The R-ratio is considered a constant, equal to the area of the port (Ap) divided by the bellows effective area. When gas lift valves are tested for both opening and closing pressures, it is possible to calculate the R-ratio. The calculated R-ratio from test data is consistently larger than the manufacturers’ published R-ratios. This paper presents a discussion of the factors affecting the R-ratio and an explanation for the difference between published and tested R-ratios. The R-ratio is not a constant but varies with dome pressure, port-material strength, bellows size, and port size. A method is proposed to calculate or test the true R-ratio.
The use of the area of the port (Ap) in the R-ratio is not completely accurate. The area should be the seal area (As) defined by the outer-sealing diameter of the ball (Ds) on the port. It is possible to test valve behavior to determine the seal area, and it is recommended that the tests be conducted in order to use the correct R-ratio when designing gas lift wells. A method to apply the use of the measured R-ratio is also provided.
O'Reilly, Daniel I. (Chevron Australia and University of Adelaide) | Hopcroft, Brad S. (Chevron Australia) | Nelligan, Kate A. (Chevron Australia) | Ng, Guan K. (Chevron Australia) | Goff, Bree H. (Chevron Australia) | Haghighi, Manouchehr (University of Adelaide)
Barrow Island (BWI), 56 km from the coast of Western Australia (WA), is home to several mature reservoirs that have produced oil since 1965. The main reservoir is the Windalia Sandstone, and it has been waterflooded since 1967, whereas all the other reservoirs are under primary depletion. Because of the maturity of the asset, it is economically critical to continue to maximize oil-production rates from the 430 online, artificially lifted wells. It is not an easy task to rank well-stimulation opportunities and streamline their execution. To this end, the BWI Subsurface Team applied the Lean Sigma processes to identify opportunities, increase efficiency, and reduce waste relating to well stimulation and well-performance improvement.
The Lean Sigma methodology is a combination of Lean Production and Six Sigma, which are methods used to minimize waste and reduce variability, respectively. The methods are used globally in many industries, especially those involved in manufacturing. In this asset, we applied the processes specifically to well-performance improvement through stimulation and other means. The team broadly focused on categorizing opportunities in both production and injection wells and ranking them—specifically, descaling wells, matrix acidizing, sucker-rod optimization, reperforating, and proactive workovers. The process for performing each type of job was mapped, and bottlenecks in each process were isolated.
Upon entering the “control” phase, several opportunities had been identified and put in place. Substantial improvements were made to the procurement, logistics, and storage of hydrochloric acid (HCl) and associated additives, enabling quicker execution of stimulation work. A new program was also developed to stimulate wells that had recently failed and were already awaiting workover (AWO), which reduced costs. A database containing the stimulation opportunities available at each individual well assisted with this process. The project resulted in the stimulation of several wells in the asset, with sizable oil-rate increases in each.
This case study will extend the information available within the oil-industry literature regarding the application of Lean Sigma to producing assets. It will assist other operators when evaluating well-stimulation opportunities in their fields. Technical information will be shared regarding feasibility studies (laboratory-compatibility work and well-transient-testing results) for acid stimulation and steps that can be taken to streamline the execution of such work. Some insights will also be shared regarding the most-efficient manner to plan rig work regarding stimulation workovers.
Manchanda, Ripudaman (University of Texas at Austin) | Bryant, Eric C. (University of Texas at Austin) | Bhardwaj, Prateek (University of Texas at Austin) | Cardiff, Philip (University College Dublin) | Sharma, Mukul M. (University of Texas at Austin)
Increasing the efficiency of completions in horizontal wells is an important concern in the oil and gas industry. To decrease the number of fracturing stages per well, it is common practice to use multiple clusters per stage. This is done with the hope that most of the clusters in the stage will be effectively stimulated. Diagnostic evidence, however, suggests that in many cases, only one or two out of four or five clusters in a stage are effectively stimulated.
In this paper, strategies to maximize the number of effectively stimulated perforation clusters are discussed. A fully 3D poroelastic model that simulates the propagation of nonplanar fractures in heterogeneous media is developed and used to model the propagation of multiple competing fractures. A parametric study is first conducted to demonstrate how important fracture-design variables, such as limited-entry perforations and cluster spacing, and formation parameters, such as permeability and lateral and vertical heterogeneity, affect the growth of competing fractures. The effect of stress shadowing caused by both mechanical and poroelastic effects is accounted for.
3D numerical simulations have been performed to show the effect of some operational and reservoir parameters on simultaneous-competitive-fracture propagation. It was found that an increase in stage spacing decreases the stress interference between propagating fractures and increases the number of propagating fractures in a stage. It was also found that an increase in reservoir permeability can decrease the stress interference between propagating fractures because of poroelastic-stress changes. A modest (approximately 25%) variability in reservoir mechanical properties along the wellbore is shown to be enough to alter the number of fractures created in a hydraulic-fracturing stage and mask the effects of stress shadowing. Interstage fracture simulations show post-shut-in fracture extension induced by stress interference from adjacent propagating fractures. The effect of poroelasticity is highlighted for infill-well-fracture design, and preferential fracture propagation toward depleted regions is clearly observed in multiwell-pad-fracture simulations.
The results in this paper attempt to provide practitioners with a better understanding of multicluster-fracturing dynamics. On the basis of these findings, recommendations are made on how best to design fracture treatments that will lead to the successful placement of fluid and proppant in a single fracture, and result in a set of fractures that are competing for growth. The ability to successfully stimulate all perforation clusters is shown to be a function of key fracture-design parameters.
Wax or paraffin formation in subsea pipelines is a major problem in the upstream petroleum industry, accounting for tremendous economic losses. Researchers have reported that approximately 85% of the world’s oils encounter problems from wax formation (Thota and Onyeanuna 2016). In this manuscript, the authors briefly discuss the mechanism of wax formation in pipelines. Next, a review of various wax-mitigation technologies is provided. The review includes citations of various thermal, chemical, mechanical, biological, and other innovative methods reported by previous researchers and used in the industry.
Han, Lihong (Tubular Goods Research Institute of CNPC and State Key Laboratory of Performance and Structural Safety for Petroleum Tubular Goods and Equipment Material) | Wang, Hang (Tubular Goods Research Institute of CNPC and State Key Laboratory of Performance and Structural Safety for Petroleum Tubular Goods and Equipment Material) | Wang, Jianjun (Tubular Goods Research Institute of CNPC and State Key Laboratory of Performance and Structural Safety for Petroleum Tubular Goods and Equipment Material) | Xie, Bin (Xinjiang Oilfield Company of CNPC) | Tian, Zhihua (Xinjiang Oilfield Company of CNPC) | Wu, Xingru (University of Oklahoma)
An oil field in Xinjiang, China, experienced a casing failure rate of 15 to 30% in thermal wells, mainly relating to inadequate protocols of casing design. This paper presents a new strain-based casing-design method. New material parameters are proposed to build safety-evaluation principles throughout the service life of a thermal well. In addition, a gas-tight thread joint is applied to prevent steam leakage that otherwise would cause a large transversal stress between different formations, and result in slip deformation of the casing string. Field practices have shown that the new method’s fitness works better for thermal wells than previously used methods.
Uetani, Takaaki (INPEX Corporation) | Furuichi, Naoto (INPEX Corporation) | Yorozu, Hirokazu (INPEX Corporation) | Sasaya, Kazuyo (INPEX Corporation) | Shibuya, Takehiro (INPEX Corporation) | Kiminami, Narihito (INPEX Corporation) | Yonebayashi, Hideharu (INPEX Corporation)
An oil well, referred to in this paper as Well B, experienced a serious emulsion problem soon after the introduction of artificial lift by use of a hydraulic jet pump. This forced the operator to reduce the production rate to meet sales-oil specifications. During its natural-flow-production period, this well experienced relatively emulsion-free operation. Consequently, the operator continued to use the same demulsifier after the jet-pump production began.
This paper presents results of a number of field trials that took place over a period of 1.5 years to control emulsions and to improve oil production. Initially, the operator raised the separator temperature, but this was not effective. Next, the operator injected xylene into the formation. Although this was reasonably successful, the effect was short term. It became necessary to open the separator-dump valve to drain the emulsions, and reduce the basic sediment and water (BS&W). This expensive operation was only undertaken to maintain production. The operator then explored changing the demulsifier-dosage rate and changing the location of the demulsifier-injection port, but neither measure was effective. Finally, a series of bottle tests was conducted to find a better demulsifier to replace the original chemical, which was no longer effective. Soon after injection of the new demulsifier, the emulsions disappeared, and the operator regained the production rate.
On the basis of the field observations and the preliminary laboratory investigations, it is determined that the emulsions that affected Well B over a period of 1.5 years were most likely caused by the introduction of artificial lift augmented by the continued used of the original demulsifier chemical, the increased production rate, and the presence of asphaltene and clay particles. An important lesson learned from this project was that emulsion-treatment programs should be reviewed periodically, especially when operating conditions change.