Hole Packer Research Articles

Blasting-enhanced water injection for coal and gas out-burst control

Coal and gas out-bursts are a major risk in deep gassy coal mines. In order to minimize the out-burst potential during the mining process, we propose a novel blast-injection integrated (BII) technology. In this technology, a group of de-stress blasts are first used to de-stress the area near the active mining face and push the stress peak further away from the mining face. The cracks generated by the blasting improve the connectivity between the pre-existing fractures and promote gradual release of gas at the mining face. This is followed by water injection directly into the coal seam through the blast holes. The injection of water can greatly improve coal plasticity and reduce the initial speed of gas diffusion, ultimately reducing the potential for violent out-bursts. To implement this technology, a set of devices were developed that include hole packers and transport and safety accessories. The BII technology was subsequently tested at an active mine. It was found that the stress relief zone in front of the coal face increased longitudinally by ∼5m, and the rate of gas emission at the mining face doubled within 30min after the de-stress blasting. The injection water volume after the de-stress blasting also increased by 25 times compared to the un-blasted condition, and the monthly gas concentration in the return airway decreased from 0.58% to 0.36%. Additionally, the concentration of dust in the return airway was found to decrease. Based on the field test results, it was concluded that BII technology is an effective measure to limit coal and gas out-burst potential.

Research and application of fracturing process for low permeability reservoir of Triassic in Junggar Basin

Baikouquan formation of Triassic in the northwest margin of Junggar Basin has long been regarded as the synonym of “alluvial fan, ultra-low permeability and no benefit”. Moreover, the effect of Triassic conglomerate reservoir reconstruction in Mabei oilfield is not obvious, which leads to ineffective production and benefit development. In this paper, based on the research results and practical production application of Triassic conglomerate reservoir fracturing reconstruction technology in Junggar Basin in recent years, four kinds of adaptive reservoir reconstruction technology for low permeability conglomerate reservoir are explored, which effectively improves the single well production and realizes the increase of reserves and productivity in conglomerate reservoir exploration. (a) In view of the three reservoir conditions of multiple sets of sand layers, large vertical oil and gas display span and large difference of stress between each set of sand layer and surrounding rock, in order to ensure that multiple sets of sand layers are effectively reconstructed, the separate layer fracturing technology is implemented. Before fracturing, the process can realize circulation fluid replacement, and after fracturing, it can realize combined production; (b) For the reservoir with poor physical properties and high formation pressure, which cannot realize the stratified fracturing of tubing packer, the casing bridge plug layered fracturing technology is adopted; (c) In view of the fact that the oil and gas reservoirs are mostly located in the upper part of the thick sand layer and the fractures extend downward to easily connect the water layer, the reservoir reconstruction technology of secondary sand addition is implemented; (d) In view of the poor physical properties of the reservoir, the oil and gas production after the vertical well fracturing is not high, or the initial oil and gas production is high, but the production decline is fast, unable to stabilize the production for a long time, the horizontal well multi-stage fracturing technology is implemented. The successful field application of the open hole packer ball sliding sleeve fracturing technology and the bridge plug perforation combined fracturing technology in horizontal wells is realized. The research and practical application of adaptive reservoir reconstruction technology further promote the reconstruction of Triassic low permeability conglomerate reservoir and single well production increase in Junggar Basin. It can be used for reference in other basins for low permeable conglomerate reservoir fracturing, and it presents good application value.

Application of Temporary Plugging Stimulated Reservoir Volume Fracturing in Mahu Conglomerate Tight Oil

On account of the influence of early technical level and transformation concept, the production of the test horizontal wells has been improved to a certain extent, but there are still some problems, such as low pressure decline, low sustainable and stable production capacity. Refracturing technology is one of the main measures to improve the output of old wells in domestic and foreign oilfields at the moment. However, the horizontal wells put into production in early stage of Mahu were segmented with open hole packer and ball sliding sleeve. Restricted by the current wellbore conditions, forced mechanical segmented refracturing could not be achieved. People make use of the high-strength temporary plugging system to automatically select geological dessert, realize multiple inter-layer and intra-layer steering, improve the complexity and sweep volume of artificial fractures, and achieve the partial function of stimulated reservoir volume fracturing, which has become the effective increase production technology and means.

Thermal breakthrough calculations to optimize design of a multiple-stage Enhanced Geothermal System

We perform an optimization and sensitivity analysis for design of an Enhanced Geothermal System (EGS) with horizontal wells and multiple fracturing stages. The sensitivity analysis includes calculations of thermal breakthrough and the maximum flow rate that can be achieved through the system. The analysis uses idealized reservoir geometry and is intended to investigate the relationship between parameters and provide insight into how to optimize an EGS, not to provide precise predictions of performance. Conventionally, EGS wells have been nearly vertical and stimulated with openhole completion in a single stage. This study investigates a design with two parallel horizontal wells. The first well is drilled and completed with casing, and then stimulated sequentially in stages with cased hole packers rated to high temperature. The second well is drilled through the stimulated region created around the first well and completed openhole. For different combinations of well spacing, lateral length, formation permeability, and number of stages, we calculate the optimal flow rate that maximizes the present value of revenue. The calculations show that stimulating with multiple stages greatly improves economic performance, delays thermal breakthrough, and allows a higher flow rate to be circulated through the system. At low well spacing and low number of stages, it is optimal to circulate fluid more slowly than the maximum possible rate in order to delay thermal breakthrough. With greater well spacing and with more stages, thermal breakthrough is relatively delayed, and it is optimal to circulate at the maximum possible flow rate. Overall, it is optimal to use the lowest well spacing where present value is maximized by circulating at the maximum possible rate. When it is optimal to circulate at the maximum possible rate, present value is sensitive to reservoir transmissivity. When it is optimal to circulate at less than the maximum possible rate, present value is unaffected by reservoir transmissivity. Increasing lateral length beyond 1000m is only beneficial for designs with relatively low lateral spacing and a large number of stages.

Numerical Simulation of Erosion Wear of Liquid-Solid Two-Phase Flow in Sliding Sleeve of Horizontal Well

In recent years, the pitching sliding sleeve staged fracturing technology of open hole packer of horizontal well is widely used in shale gas, dense reservoirs, low permeable reservoirs and other exploration and development fields, and becomes the important means of present oil-gas field stimulation. But in the construction process of horizontal well fracturing, the abnormal condition that the sliding sleeve is not opened or is opened invisibly is occurred repeatedly, which has big impact on the fracturing construction. Based on fluid dynamics method and Finnie micro-cutting theory, this paper simulated the erosion wear rate of ball seat at the different fracturing segments. The results showed that: the construction displacement has big impact on the erosion wear, followed by the particle size of proppant and sand ratio, wherein the erosion wear is in inversely proportional to the particle size of proppant; and when multistage fracturing, the possibility that the sliding sleeve close to the toe end and heel happens erosion destruction is much less than that of sliding sleeve in the middle.

Hole packer and seal for oil and gas wells

Hole packer and seal for oil and gas wells

Case Histories of Successful Acid Stimulation of Carbonate Completed With Horizontal Open Hole Wellbores

Abstract Horizontal open hole wellbores in carbonate formations have become an everyday occurrence to improve production economics. Carbonate formations are typically stimulated by using hydrochloric acid. An acid treatment in the well configuration described provides a significant challenge in diversion to accomplish complete stimulation of the lateral. Various techniques have been employed to overcome this problem. These include pre-perforated or slotted liners, specialty treating fluids, solid diverting materials and tools. All have had some successes in various regions of the world. Presented are three case histories in which open hole packers and sliding sleeves have been employed with and without the aid of specialty treating fluids. These cases cover Devonian TVD 3,170 m (10,400 ft), Devonian TVD 2,682 m (8,800 ft) and San Andres TVD 1,737 m (5,700 ft) formations. Details of these treatments, as well as production responses, are discussed. Introduction Stimulation of carbonate reservoirs is typically used to restore or enhance production to an economic level. Acid, whether organic or inorganic in nature, is a natural means of effecting such stimulation of these types of lithologies(1–8). Acid fracturing is the most widely used technique for deep stimulation of limestone or dolomite formations. Matrix treatments, whether at a minor injection rate (low permeability reservoirs) or at high rates (high permeability reservoirs), are also commonly used to effect a shallow damage bypass. San Andres and Devonian Formations are common carbonate reservoirs producing in the Permian Basin with lithologies, depths and bottomhole temperatures that vary significantly. In addition, horizontal completions are becoming routine in some areas where these formations are being produced. Geologic and Reservoir Descriptions Devonian Microscopic examination of core samples in the area of the treated wells revealed a mixture of the following lithologies: chert, cherty limestone, limey chert, dolomitic cherty limestone and dolomitic limey chert(9–11). Microporosity, rather than interparticle porosity, has been created by partial substitution of the original limestone matrix by silica (chert). The post-depositional processes included karst weathering, cave wall deposition and collapsed cave material accumulating as brecciated chert zones. Figure 1 illustrates the variance of the composition through the Devonian in the wells at 2,682 m (8,800 ft) TVD. The Devonian is a solution gas drive reservoir with some water production. Original bottomhole pressure was found to be approximately 38,611 kPa (5,600 psig) from a DST in 1986. Bottomhole temperature is approximately 57 °C (135 °F). Permeability varied from less than 0.01 mD to greater than 16 mD, with an average of approximately 2 mD. Porosity varies from less than 1% to greater than 13%, with an average of approximately 11%. San Andres The San Andres (~1,737 m, 5,700 ft) is a Dolomitic Formation with solution gas drive in combination with gas cap expansion(9, 12). Average permeability is over 9 mD with an average porosity greater than 13%. Acid solubility varies from 78 to 92% in 15% hydrochloric acid. The main components of the lithology are Dolomite (77 to 92%) and Anhydrite (3 to 20%). Bottomhole temperature is typically around 38 °C (100 °F). These values are illustrated in Figure 2.

A borehole flowmeter investigation of small‐scale hydraulic conductivity variation in the Biscayne Aquifer, Florida

Geostatistical analysis of closely spaced borehole flowmeter measurements was used to estimate the variance (2.53) and vertical and horizontal correlation lengths of ln K(0.57 and 7.3 m) in the Biscayne Aquifer, a limestone aquifer critical for Florida's water supply and for Everglades restoration efforts. The variance and correlation lengths of the Biscayne Aquifer are similar to some of the values for unconsolidated siliciclastic sediments (especially those at Columbus, Mississippi∥. The larger λh, for the Biscayne Aquifer (7.3 m) is thought to be due at least in part to the lower lateral variability of the carbonate platform depositional environment, compared to the fluvial environments in which the siliciclastic sediments were deposited. An improved down hole packer would allow for data with finer vertical resolution; the current system is adequate for work inside well screens but cannot adequately seal many spots in open, irregular rock boreholes. Research in rock presents additional logistical difficulties but is important for addressing fundamental questions about solute transport in a wider range of geological media, beyond unconsolidated siliciclastic deposits.

Horizontal Well Gas/Water Shutoff-Field Results

Abstract Many horizontal wells have been drilled to control gas or water coning. However, after breakthrough, attempts to control inflow location along these wells have been expensive and frequently unsuccessful in reducing GOR and WOR. Cemented casing, casing with ECPs, open hole packers, selective stimulation and formation plugging agents have all been tried. Husky's experience with slightly inclined wells, over the past several years, suggested a "new" technique, which has recently been proven successful. Simply lowering tubing in a well, slightly inclined from horizontal, resulted in doubling of oil production rate and reducing gas production by 50%. Details of well configuration, field production results and a simple analytical model, explaining why it works, are presented in this paper. Special reservoir conditions which must exist for this technique are also discussed. Introduction One of the most successful applications of horizontal wells has been the reduction of gas or water coning(1–6), while at the same time improving areal drainage(7. 8). However, because of reservoir heterogeneity and pressure gradients across a reservoir, caused by production and injection operations, breakthrough of gas or water often occurs in one small part of a horizontal well. The resulting production of large amounts of gas or water with the oil increases processing cost and depletes reservoir energy. Therefore many attempts have been made to control inflow from along horizontal wells. Cemented casing, casing with ECPS(9), open hole packers(7), selective stimulation(5) and formation plugging agents(4) have all been tried, often without success. While experimenting with slightly inclined wells, a possible "new" way to control excess gas and water production was discovered. Husky has drilled slightly inclined wells in the Black, Rainbow, and Rainbow South Fields to eliminate uncertainty of oil/water contact location(9), and to drain oil from a moving oil bank in waterflooded pools with a gas cap, but no gas injection. There are several other possible reasons to drill a slightly inclined well, including to drain multiple porosity stringers and to allow the end of the well to be plugged off when excess gas or water production occurs. Production logs have shown that horizontal wells can act as good horizontal separators(3. 11). Also, drawdowns in many horizontal wells have been shown to be very low, in the range detectable only by quartz or sensitive strain gauges(7). These factors suggest that it might be possible to control the type of fluid being produced from some wells by simply changing the tubing inflow points. Although many authors have explored the effects of pressure drops in horizontal wells(12. 13), the specific use of variable tubing inflow points to control producing GOR or WOR has not been clearly stated. Analytical Model A simplified spreadsheet model was built to evaluate wellbore pressure changes and fluid inflow along a slightly inclined wellbore. The model incorporates the effects of productivity, gravity, momentum and single phase friction pressure drop. The tubing inflow location to achieve maximum flow of oil without gas or water production was evaluated.

Redeveloping Mature Miscible Flood Reservoirs With Horizontal Wells: A Summary Of Six Years Of Experience

Abstract Husky operates seven mature vertical hydrocarbon miscible floods in the Rainbow Field. Up to June 1993, eleven horizontal wells have been drilled, one horizontal well re-entered for extension and one vertical well re-entered to drill a lateral. Even though these wells were all drilled into mature miscible floods, the variation of reservoir characteristics, the horizontal well location and exploitation strategy made each well unique in terms of drilling, completion, workover and production performance. This paper describes the evolution and improvements in horizontal well applications made in redeveloping these mature reservoirs. Advancements are described in several areas as follows: Drilling:the use of pilot holes;entering the reef laterally;overcoming damage, loss of circulation, and high torque and drag; andextending the existing horizontal hole. Completions and workovers:selective testing and stimulation of different zones along the horizontal hole using multiple open hole packers and sliding sleeves, or straddle packers on tubulars. Production strategy and reservoir optimization of EOR performance:controlled rate to approximtely twice vertical well rates;controlled vertical movement of the oil bank;interference tests with vertical wells;use of bottom hole chokes; anduse of circulation strings for combating asphaltene deposition. Introduction The potential applications of horizontal wells in miscible floods have been mentioned in previous papers(1–3). However, Husky's well 16-29-108-08W6M was the first field application(4). Later, other companies have also used horizontal wells in miscible floods(5). Husky has redeveloped six pools (Figure 1) since March 26, 1989, to improve the recovery of oil sandwiched between solvent and water zones in vertical hydrocarbon miscible floods, by drilling eleven new horizontal wells, one horizontal extension and one vertical well re-entry. The abbreviated well names on Table 1 will be used throughout the remainder of this paper. There have been significant differences in the drilling, completion and production techniques and problems encountered on these horizontal wells. Each well has outperformed its vertical offsets in the same pool in terms of oil production rates (Figure 2) and GOR (Figure 3), which is unique for such a large well program. The vertical well rates and GOR's are averages of all vertical wells producing the reservoir behaves as a typical pool with water drive. Because reservoir pressure has been largely maintained, the dominant depletion mechanism is water influx. Infill Vertical Wells Following development of the northern part of the pool on a 32 ha (80 acre) spacing pattern, about a dozen vertical wells were drilled on 16 ha (40 acre) spacing, either as infill wells or as pool edge (step-out) wells. In five wells which are truly infill wells, the initial (first-year) oil rate was lower than the initial oil rate for the four surrounding original vertical wells; except for the well in Lsd. 11-3-5-32WIM, the total daily fluid was also less than it was in the surrounding original vertical wells (Table 2).

Extended Reach and Horizontal Wells Experienced on the Statfjord Field

Statfjord field, the largest producing field in Europe, is located 200 km northwest of Bergen, Norway on the United Kingdom/Norwegian boundary. Statfjord field is being developed with three fully integrated platforms of concrete gravity based on Condeep design. The Statfjord field consists of four reservoirs: Upper Brent, Lower Brent, Dunlin, and Statfjord, which are developed separately. The overall objective for the horizontal and extended reach wells on Statfjord is to maximize the field recovery and accelerate production at a minimal cost. This is done by drilling extended reach wells to the far-away flanks of the field and drilling horizontal wells to drain fault blocks and erosion zones in the Brent reservoir and wedge zones in the Statfjord reservoir. To date, a total of 11 horizontal and extended reach wells have been drilled and completed on Statfjord field. The following have been key factors in drilling the horizontal and extended reach wells: well profile, torque and drag, equipment limitations, hole cleaning, hole stability, mud and cement programs, and surveying. To optimize the well profiles, extensive work has been put into simulating torque, drag, and ECDs. The well profiles are optimized with regards to drilling, completion, and workover, in addition to themore » reservoir targets. The completion is designed to be able to perform all future work through tubing. Factors like zone isolation requirements, well profile, casing program, logging/testing/perforating requirements, and sand production are considered when planning the completion. A 7 in. monobore completion string together with a 7 in. cemented liner is used to meet the completion objective. Several production logging tool, bridge plug, and perforation jobs have been performed on coiled tubing in horizontal wells on Statfjord field. Problems related to hole cleaning, well killing, fishing, and packer setting have been experienced during drilling and completion of the wells.« less

Developments in in situ permeability testing

Abstract Assessment of field permeability of soil and rocks can be made using the various techniques outlined in BS 5930, Section 4. Recently, two additional techniques have been used; the slim hole packer testing equipment developed by Soil Mechanics Limited, and the multiple port piezometer Westbay system. This paper describes the equipment and methods used, together with examples of the results obtained. A suite of slim hole packer equipment has been developed to provide testing capability in very low to moderate permeability ground (10 −10 to 10 −5 m s −1 ). Pressures are measured with either a manometer board or transducers and flows monitored using a parafin/water manometer or gapmeters. An on-site computer is used to record and plot test data and calculate permeability results. The Westbay multiple port piezometer system consists of plastic casing, connected with ‘o’-ring seal couplings, installed in a borehole. Casing lengths can be selected so as to divide the borehole into a series of isolated response lengths. The couplings can incorporate monitoring ports for water pressure measurement and groundwater sampling or pumping ports for permeability testing and groundwater. This system has been used to carry out rising head tests by first lowering the water level in the access tube and then recording the change in water level either by using a dipmeter inside the access tube, or via an adjacent monitoring port using a Westbay electronic pressure probe.

The U.S. hot dry rock project

Early attempts to hydraulically fracture and connect two wells drilled at the Hot Dry Rock (HDR) site at Fenton Hill in New Mexico produced a large volume of fractured rock, but no connection. Microearthquakes triggered by fracturing indicated that the stimulated rock zones grew in unexpected directions. Consequently one of the wells was sidetracked at a depth of 2.9 km. It was redrilled into the zones of most intense microseismic activity, and flow connections were achieved. Hydraulic communication was improved by supplemental stimulation using recently developed high temperature and high pressure open hole packers. Preliminary testing indicates a reservoir with heat production capability which greatly surpasses that attained in the earlier Phase I reservoir. Longer term testing in 1987 and 1988 will provide more complete information on reservoir behaviour.