Surface Injection Pressure Research Articles

A workflow for estimating the CO2 injection rate of a vertical well in a notional storage project

A workflow that considers regulatory and technical constraints applicable to subsurface CO2 injection projects was developed to determine fluid injection rates accurately. The constraints considered include, but are not limited to, maximum injection bottomhole pressure, maximum injection pressure at the surface or wellhead pressure, and threshold vibration velocity. The workflow was developed and tested using a reservoir model developed from site characterization data of an Illinois Basin CarbonSAFE Phase II notional storage project. The Nexus® reservoir simulation software suite and the Peng-Robinson equation-of-state were used to perform compositional dynamic simulations. Reservoir modeling results indicated that (1) the regulated and technically feasible CO2 injection rate of a vertical well is predetermined by the most stringent parameter amongst maximum bottomhole pressure, maximum wellhead (surface injection) pressure, and threshold vibration velocity constraints; (2) the threshold vibrational velocity constraint predetermines CO2 injection rate for high-permeability injection zones; and (3) the most stringent constraint for low-permeability injection zones could be either the maximum bottomhole pressure or the maximum wellhead pressure. However, the injection rate may be further reduced if faults or hydraulically conductive fractures are present within the injection zone and adjacent formations because the pressure required to reactivate the faults may be lower than maximum injection bottomhole pressure, maximum wellhead pressure, and vibrational velocity constraints.

Study on the influence of injection molding parameters on the warpage using simulation and Taguchi method

Injection moulding (IM) is a processing technique produced from polymeric products. Warpage defect (WD) is the defect that generally occurs during the IM process due to the inappropriate processing parameters of the melt temperature, mould surface temperature, packing pressure, injection pressure, and packing pressure time. This paper investigates the IM parameters that influence product warpage by combining the simulation, analysis of variance, signal-to-noise analysis, and Taguchi method. The simulation process was performed by Moldflow software. The product material is high-density polyethylene. The WD has been predicted and optimized to enhance product quality. Melt temperature and packing pressure time are the factors that acrimoniously influenced the warpage of the product. The results show that the packing pressure time and melt temperature have the highest effects on the WD by the contributions of 48.94% and 37.48%, respectively. The optimal IM parameters are scanned again with the WD abated at about 1.2%. The mathematical formula has been constructed to predict the WD with the reflection of acceptable values of 86.29%. The research hopes that the results have been applied to designing and fabricating the plastic product in the near future.

New Mathematical Technique for Step Rate Test Analysis Aids Determination of Fracture Pressure and Overcomes the Uncertainty of Conventional Analysis.

Experience in the oil industry has shown that it is challenging to sustain successful long-term matrix injection, as injection water quality cannot be maintained rigorously due to facility hiccups and membrane clogging. Most oil field operators have resolved this problem of injectivity decline by increasing the surface injection pressure to part the formation and inject just above the fracture gradient with strict offtake management for zonal conformance. This is not an easy task as injection much above fracture opening pressure can lead to water fingering and poor sweep that results in uneconomical waterflood recovery. The operators, thus, strive to inject at a pressure just above the fracture opening pressure so that the fracture opens near the wellbore but does not extend and then maintain the pressure just above the fracture closing pressure. Therefore, determination of the fracture opening pressure and fracture closing pressure has remained critical data for the success of waterflood projects. The most reliable industry approach to estimating fracture opening and fracture closing pressures comes from the step rate test (SRT). This traditional approach of Cartesian analysis of pressure-rate plot fits straight lines through the data in a plot of injection pressure against injection rate and then estimates the fracture pressure from the intersection of these lines having different slopes. The data received often do not exhibit one clear change in slope, thus resulting in multiple possible solutions, making it difficult for the operator to use the data for high CAPEX facilities design. Most past studies indicate the subjectivity of this Cartesian slope fitting technique. Alternative solutions through multirate superposition analysis found limited application in the analysis of SRT data due to considerable sensitivity to the value of initial pressure used for superposition and lack of stability of rate and pressure data. In this article, a new technique of SRT analysis is presented, which provides a unique solution for fracture opening and fracture closing pressures. It helps to overcome the limitations of the traditional technique of arbitrary fitting of straight lines. It uses the mathematical understanding of cumulative derivatives to recognize that the matrix opens when the cumulative growth of the rate of injectivity shows a change. It estimates the derivative of the injection rate with respect to injection pressure at each step. Then, it estimates the fracture pressure from the plot of the cumulative of this derivative against pressure at each step. It helps to overcome the challenge SRT solutions posed by the nonlinear trend of pressure data at each injection step both before fracture and after fracture is initiated. It also overcomes the limitations of the multirate superposition technique, as it is not sensitive to the value of initial pressure used for superposition.

Downsizing, Use of Dummy and Venturi Valves Enhance Gas Lift Performance

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 213975, “Gas Lift Performance Enhancement Strategies by Downsizing and Using Dummy and Venturi Valves: A Paradigm Shift in Gas Lift Systems Management Philosophy,” by Wael F. Akeil, Ahmed M. El-Bohoty, and El-Sayed I. Abd El-Mawla, Gulf of Suez Petroleum Company, et al. The paper has not been peer reviewed. _ A mature offshore Egyptian field has entered a depletion phase. Most of its gas lift design bases were initiated during production startup and feature standardized sets of large gas lift valve port sizes with narrow spacing. Inconsistent well flow during reservoir depletion adds complications to the system. Therefore, a screenout model was created to select candidate wells for downsizing and for changing out with dummy and Venturi valves. After screening, 70 wells were selected for application of the new strategy. The complete paper discusses the effectiveness of smaller port sizes and the use of dummy and Venturi valves in enhancing gas lift performance and maximizing recovery. Field Background The field is divided into four main geographical quadrants, each with its own facilities. Total production currently is approximately 60,000 BOPD with an average water cut of 85%. Exploration and development of the field saw the drilling of more than 460 wells; half of these currently are experiencing reservoir pressure decline, drained reserves, or operational problems. Most wells are gas lifted, and the remainder either use electric submersible pump (ESP) installation or flow naturally. The facility consists of 73 offshore satellite platforms containing the wells—both oil producers and water injectors—connected to nine offshore complex platforms. As a part of continuous improvement trials, the operator reviewed the process of gas lift system management to introduce necessary improvements and recommend changes for long-term plans. The proposed amended management system was the result of monitoring, troubleshooting, and optimization activities outlined in the complete paper. Amended Gas Lift Management System Using Dummy Valves in Gas Lift System. Conceptual Phase. A dummy valve is a special gas lift valve shaped like solid metallic bar with upper and lower packings. They are installed to replace unloading valves that are no longer needed. Installing dummy valves instead of the unloading valves can reduce problems such as valve interference and deepens the point of gas injection. Redesign Procedure Based on the New Production Profile. This practice can be applied in two main cases: First, if reservoir pressure has declined and the well is producing with a lower rate but the surface injection pressure is still high enough to reach deeper valves; and, second, if the well is planned to be recompleted from one formation to another that has a higher reservoir pressure but with lower formation feed as the result of lower productivity. The main steps for redesign are provided in the complete paper.

Water-Plus-Gas Injection on a Bakken Well Pad May Solve Problems That Stymied Shale EOR

_ After years of enhanced oil recovery (EOR) tests in the Bakken, one method finally appears to have added to a well’s ultimate production. The Liberty Resources well “is perhaps the first one that had clear, indisputable evidence of incremental oil. I do firmly believe we are on the right track for cracking the code for Bakken EOR,” said Jim Sorensen, director of subsurface R&D for the University of North Dakota Energy and Environmental Research Center (EERC) which provided technical support and funding. The gain predicted after the treatment with water alternating with gas injection (WAG) is not huge. A paper on the test, which was limited to a single 30-day injection cycle, estimated it added 7,000 bbl to the ultimate production, based on decline curve analysis (URTeC 3722974). An updated analysis from EERC is expected in early 2023. While there are endless arguments over the accuracy of decline curve analysis, Gordon Pospisil, development advisor for Liberty, said incremental oil estimates look solid: “The oil rate response to water alternating gas injection was clearly measurable at over 7,000 bbls over the baseline trend.” The bigger news may be an injection method that can overcome two barriers to EOR in the Bakken and elsewhere. One is finding a way to keep the injected gas around the wellbore, and the other is significantly lowering the cost, primarily by slashing the volume of gas required. “Overall, we were pleased with the project outcome to date as we were able to build pressure, contain the injection within the DSU (drilling spacing unit), and make incremental oil,” Pospisil said. For the test, Liberty used a novel, computer-controlled injection system from a startup company, EOR ETC. This system can rapidly switch from gas to water injection based on the control system the company developed. This reduces the surface injection pressure required to significantly increase the downhole pressure level and helps contain the gas in the target zone. “I have never seen anything like that. It performed as advertised,” Sorensen said. The estimated long-term gain looks small compared to the 800,000 bbl of oil prior to the test. But Brian Schwanitz, president of EOR ETC, said the income from those barrels covered what they billed for pumping the job, which was a discounted rate reflecting Liberty’s willingness to be the first operator to use the device. What it accomplished stands out compared to the futility of past Bakken tests where far more gas was injected with little impact on the downhole pressure because so much of it leaked off through the fractured formation. The Bakken Debacle For a decade, companies in the Bakken, often in partnership with the EERC, have searched for ways to get more oil out of the play where the ultimate recoveries are usually below 10% of the oil in place, which is in line with other unconventional oil plays. Gas-injection EOR tests in oil-producing shale plays have been hit or miss, with most of the results in the Bakken in the miss column. The problem has been that much of the gas escapes from the target zone, making it impossible in some cases to achieve the pressure levels needed for effective EOR and it increases the volume of gas needed to uneconomic levels for gas-only projects to achieve improved ultimate recoveries.

Experimental investigation of heat transfer for diesel spray impingement on a high temperature wall

In this paper, the heat transfer characteristics of spray-wall impingement on a high temperature wall were studied by using a transient thermocouple and a one-dimensional finite-difference conduction model to obtain variations of wall temperature and heat flux. Results showed that increasing the injection pressure and decreasing the ambient temperature both caused an increase in surface heat flux and heat transfer coefficient. However, with the increase of the initial surface temperature from 200 to 600 °C, the surface heat flux and heat transfer coefficient first increased and then decreased, and reached the maximum at about 520 °C and 390 °C respectively, which was due to the change of heat transfer regime on the wall. The contribution of experimental factors descended in the order of initial surface temperature, injection pressure and ambient temperature. The dimensionless surface heat fluxes in terms of Biot and Fourier numbers were highly similar and a dimensionless correlation was developed to quantify this heat transfer behavior, which showed that the ratio of the thermal resistance of the high temperature wall to the thermal resistance of convection heat transfer on the wall surface changed almost linearly during the process of spray-wall impingement.

Recent water disposal and pore pressure evolution in the Delaware Mountain Group, Delaware Basin, Southeast New Mexico and West Texas, USA

Study regionA flat, large, semi-arid plateau in the southwest United States (west Texas and southeast New Mexico) underlain by a deep Paleozoic sedimentary basin, the tectonic Delaware Basin, host of intensive hydrocarbon production. Study focusImpacts of injection of large volumes of water produced from oil and gas wells and injected through 1000 + disposal wells, in particular, pressure buildup, induced seismicity and their potential consequences, in a formation underlying fresh-water aquifers but separated from them by thick layers of evaporites. The target formation is the Delaware Mountain Group (DMG) of Permian age and consisting of up to 4500 ft (~1400 m) of mostly fine-grained, deepwater siliciclastic slope and basin deposits (sandstones, siltstones, and minor limestones). A flow model was developed and calibrated from well log data, stratigraphic data, petrophysical analyses, and core data (123 ×170 mi2 - 1 ×1 mi2 grid size) complemented with dynamic injectivity information based on surface injection pressures and rates of the disposal wells. New hydrological insights for the regionInjection of 5.8 billion barrels (0.92 billion m3) of waste water has generated regional pressure increases in the DMG mostly in the 100–400 psi (0.7–2.8 MPa) range: (1) creating strong artesian conditions that, combined with the presence of numerous historical boreholes, could connect DMG and fresh-water aquifers; and (2) generating conditions leading to actually observed moderate induced seismicity.

Seismicity induced by massive wastewater injection near Puerto Gaitán, Colombia

SUMMARY Seven years after the beginning of a massive wastewater injection project in eastern Colombia, local earthquake activity increased significantly. The field operator and the Colombian Geological Survey immediately reinforced the monitoring of the area. Our analysis of the temporal evolution of the seismic and injection data together with our knowledge of the geological parameters of the region indicate that the surge of seismicity is being induced by the re-injection of produced water into the same three producing reservoirs. Earthquake activity began on known faults once disposal rates had reached a threshold of ∼2 × 106 m3 of water per month. The average reservoir pressure had remained constant at 7.6 MPa after several years of production, sustained by a large, active aquifer. Surface injection pressures in the seismically active areas remain below 8.3 MPa, a value large enough to activate some of the faults. Since faults are mapped throughout the region and many do not have seismicity on them, we conclude that the existence of known faults is not the only control on whether earthquakes are generated. Stress conditions of these faults are open to future studies. Earthquakes are primarily found in four clusters, located near faults mapped by the operator. The hypocentres reveal vertical planes with orientations consistent with focal mechanisms of these events. Stress inversion of the focal mechanisms gives a maximum compression in the direction ENE-WSW, which is in agreement with borehole breakout measurements. Since the focal mechanisms of the earthquakes are consistent with the tectonic stress regime, we can conclude that the seismicity is resulting from the activation of critically stressed faults. Slip was progressive and seismic activity reached a peak before declining to few events per month. The decline in seismicity suggests that most of the stress has been relieved on the main faults. The magnitude of a large majority of the recorded earthquakes was lower than 4, as the pore pressure disturbance did not reach the mapped large faults whose activation might have resulted in larger magnitude earthquakes. Our study shows that a good knowledge of the local fault network and conditions of stress is of paramount importance when planning a massive water disposal program. These earthquakes indicate that while faults provide an opportunity to dispose produced water at an economically attractive volume–pressure ratio, the possibility of induced seismicity must also be considered.

Gas Lift Operations Require Accurate Predictions of Downhole Annulus Pressure

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 190929, “Gas Lift Annulus Pressure,” by Kenneth Decker, SPE, retired, and Robert P. Sutton, SPE, consultant, prepared for the 2018 SPE Artificial Lift Conference and Exhibition—Americas, The Woodlands, Texas, USA, 28–30 August. The paper has not been peer reviewed. Downhole annulus pressure is required for any gas lift design. This paper presents several methods of determining annulus pressure at depth and helps determine which method is most appropriate for specific conditions. It also provides advice on the accuracy of a combination of different critical properties and compressibility correlations, offers an alternative design technique to account for changing annulus temperature during unloading, and provides guidelines for modeling changes in annulus pressure during unloading. Introduction While many methods of computing gas pressure in a flowing environment are available, what is needed in the case of gas lift is the static annulus pressure at depth. Historically, the method of using average temperature and pressure to compute compressibility factors and assuming linear well-temperature gradients made gas lift design relatively simple. The small errors were tolerable and within the normal design safety mar-gins of operating systems with surface pressures of less than 1,500 psi. When surface injection pressures exceed 1,500 psi, calculations become more important. Computers are now used to calculate downhole annulus pressure, and the designer must trust the number that appears on the computer screen. That trust may not be warranted, depending on the method of calculation. The small errors that creep into computer calculations increase linearly as surface injection pressure increases. Additionally, the choice of which correlation to use to model the critical properties of the gas and which compressibility factor correlation to use also affect the accuracy of the calculation. As a gas lift well transitions from a geothermal to a flowing temperature profile during unloading and lifting, the annulus pressure at depth decreases despite surface injection pressure remaining unchanged. The change in annulus pressure is governed by the volume of gas present in the annulus. Reduction in gas volume decreases pressure. Traditional design techniques ignore this reality and substitute a simplified analogy of valve performance that incurs errors and misconceptions about how the annulus pressure changes during unloading. A more-detailed discussion of these issues and proposed questions for program developers is presented in the complete paper. Annulus Pressure Calculation Methods Methods of determining downhole annulus pressure include monographs, density equations used to full depth with average pressure and temperature, and density equations used in small depth increments with average temperature and pressure within the increment. An examination of one of these monographs is shown in Fig. 1. The choice of which method to use comes with limitations on the accuracy of the predicted pressure at depth.

CO2 storage in depleted oil and gas fields in the Gulf of Mexico

Depleted oil and gas reservoirs are one of the prime-candidate formations for geologic CO2 storage. Although both the geological structure and the physical properties of most of them have been extensively studied and characterized, there is limited data on the assessment of the CO2 storage capacity, especially in the offshore fields. The purpose of this study is to develop a high-level quantitative assessment of the CO2 volume that can be stored in depleted oil and gas fields in the Federal offshore regions of the Gulf of Mexico (GOM), both on a field-by-field and on a reservoir-by-reservoir basis. In this study, we simulated CO2 storage in 461 of the depleted oil and gas reservoirs (73 fields) among 3514 reservoirs (675 fields) in the GOM (2013 BOEM Reserves database). Based on the simulation results, we improved the Department of Energy (DOE) CO2 Storage Resource Estimate Equation to make more refined and accurate estimates of storable CO2 volumes. Newly revised efficiency factor (ERoil/gas) correlates better with hydrocarbon recovery factor (HCRF), which is found to be a strong indicator of the CO2 storage capacity of the reservoir. The higher HCRF results in higher ERoil/gas. The further investigations resulted in an improved, material balance-based correlation—which is called the Production-CO2 Storage Correlation—between cumulative production (free gas, oil and water) at reservoir conditions and CO2 storage volume at standard conditions. This relationship, which is unique for all three types of reservoirs (gas, oil and combination), allows for making direct estimates of CO2 storage volume using only existing production data. Application of these correlations to all of the depleted fields (3514 reservoirs) yields CO2 storage capacities of 4748 MMtons, and the CO2 storage capacity in all 1295 depleted and active fields (13,289 reservoirs) in the GOM calculated to be 21.57 Billion tons. If a 5000 psia surface injection pressure constraint was applied, these volumes would be reduced to 4075 MMtons for all depleted fields only and to 15.80 Billion tons for all depleted and active fields in the GOM. The production-CO2 storage correlations can be used to make more accurate CO2 storage volume estimates in all onshore and offshore depleted oil and gas fields.

Pressure/flow modeling and induced seismicity resulting from two decades of high-pressure deep-well brine injection, Paradox Valley, Colorado

The Bureau of Reclamation operates a deep injection well near Paradox Valley, Colorado. Intermittent injection testing began in 1991, followed by near-continuous injection since 1996. Daily average injection flow rates and surface injection pressures have been recorded since 1991, and seismicity has been monitored since 1985. Before the injection flow rate was decreased in 2013 in response to the largest induced earthquake to date, observed wellhead pressures were increasing and approaching the maximum permitted pressure. Potential solutions were needed to provide long-term reductions in wellhead pressures and to minimize the occurrence of future large-magnitude induced earthquakes. A key step in this process is to establish whether the trend of increasing pressures is more likely caused by far-field reservoir pressurization or near-well flow impairment. The spatiotemporal occurrence of induced seismicity is fit relatively well by a 1D diffusive triggering front relationship, suggesting that the reservoir can be modeled as a porous medium. Simple 1D, uncoupled porous models are therefore used to analyze the wellhead pressure response for the period of long-term injection. These simple models are found to provide a reasonable fit to the pressure/flow data. We did not observe the expected changes in the model parameters that would indicate significant near-well flow impairment, and thus we have concluded that the observed pressure increase is more likely related to far-field pressurization. Somewhat surprisingly, given the complex geologic structure and the heterogeneity in the locations of induced seismicity, the analysis demonstrates the ability of a simple radially symmetric porous model to fit the pressure/flow data in the near-well area (within approximately 2 km). Although the induced seismicity data suggest significant heterogeneity, the daily average wellhead pressure/flow data are insensitive to these features. In the absence of additional constraints, use of more complicated models is unlikely to produce substantial additional benefit for modeling in the near-well area.

The Research and Evaluation of Finely Layered Water Injection Standard in Low-Permeability Reservoirs - A Case from Block A in one Low-Permeability Reservoir

Due to the common problems of waterflood in low-permeability reservoirs, the reasearch of finely layered water injection is carried out. This paper established the finely layered water injection standard in low-permeability reservoirs and analysed the sensitivity of engineering parameters as well as evaluated the effect of the finely layered water injection standard in Block A with the semi-quantitative to quantitative method. The results show that: according to the finely layered water injection standard, it can be divided into three types: layered water injection between the layers, layered water injection in inner layer, layered water injection between fracture segment and no-fracture segment. Under the guidance of the standard, it sloved the problem of uneven absorption profile in Block A in some degree and could improve the oil recovery by 3.5%. The sensitivity analysis shows that good performance of finely layered water injection in Block A requires the reservoir permeability ratio should be less than 10, the perforation thickness should not exceed 10 m, the amount of layered injection layers should be less than 3, the surface injection pressure should be below 14 MPa and the injection rate shuold be controlled at about 35 m3/d.

Technology Focus: Coiled Tubing Applications (June 2010)

Technology Focus I guess it is no surprise to the people who manufacture coiled tubing (CT) or to those of us in the CT-service industry who actually buy it, but CT is getting bigger. After a decade during which the most common size was 1½ in., the position changed in 2008 when 1¾ in. finally took top spot. Only 1 year later, 2-in. CT took the pole position. What, might you ask, is driving this growth in pipe diameter? The answer is: “Horizontal wells.” In the past few years, we have seen explosive growth in the number of horizontal wells drilled, with much of that growth occurring in the North American shale market. However, the increase in pipe size is driven not only by an increased number of horizontal wells but also because lateral reach is increasing and because completion methods are evolving. Tight-gas-completion methods routinely encompass techniques that use CT for perforating, composite-plug mill-outs, fracture-port ball-seat mill-outs, and fracture-sand cleanouts. The larger-diameter CT is required for greater lateral reach and to enable adequate weight on bit for effective milling operations. Also, because solids removal still requires the same fluid-circulation rates while strings are getting longer, then inevitably, CT diameters must increase to keep surface injection pressures manageable. Bigger, heavier strings inevitably cost more; and because of equipment-size limitations, these strings are subjected to greater bending strain, which in turn results in a shorter working life. One might imagine that we could be reaching an economic limit on string size, but in fact there currently is no sign that this trend is abating. So, is the answer just to build bigger and bigger equipment? One risk of concentrating solely on the CT handling equipment is that the equipment becomes increasingly focused on specific well types and applications, and, in turn, CT loses its versatility for everyday intervention operations. Right now, the jury is still “out,” but it remains a question of whether the various technology initiatives aimed at extending CT horizontal reach will ever meet the operators’ expressed desire for ever-longer horizontal wells and, in turn, how that will influence the CT industry. Coiled Tubing Applications additional reading available at OnePetro: www.onepetro.org SPE 130632 • “Deliquefication of South Texas Gas Wells Using Corrosion-Resistant Coiled Tubing: A 6-Year Case History” by K.L. Poppenhagen, SPE, ConocoPhillips, et al. SPE 130625 • “New Field in East Siberia: Challenges of Performing CT Operations in Vankorskoe Field” by V. Bochkarev, Rosneft, et al. SPE 130579 • “Laminar and Turbulent Friction Factors for Annular Flow of Drag-Reducing Polymer Solutions in Coiled-Tubing Operations” by C.C. Ogugbue, SPE, University of Oklahoma, et al.

THE RECOGNITION AND ALLEVIATION OF COMPLEXITY WITH HYDRAULIC FRACTURING ONSHORE AUSTRALIA

Increasingly demanding contractual obligations and more cost-effective technology has led to the widespread use of hydraulic fracture treatments of wells onshore Australia. Whilst historically confined to low permeability, marginal fields, the majority of natural gas wells in some areas of onshore Australia are now routinely hydraulically fractured. However, a number of wells in localised regions have displayed treatment difficulties. Such wells consistently display common symptoms, such as the inability to inject proppant at required concentrations without exceeding surface injection pressure limitations. Fracture treatments on these wells are often prematurely terminated (or 'screen-out'), mainly because of near-wellbore fracture complexity. Such wells invariably display poor post-stimulation productivity.This paper describes the evaluation of reservoirs on the basis of in-situ stress and their propensity for fracture complexity. Simple, recognisable treatment pressure signatures, which indicate the presence of near-wellbore tortuosity, are presented. A conventional single, planar fracture simulation model confirms the presence of fracture tortuosity. Proppant-free shear dilation, herein referred to as a 'water-frac', has been analysed as an alternative fracture treatment in which natural fractures are inflated to interconnect with each other, forming a conduit for hydrocarbon flow. This alleviates near- wellbore fracture complexity and may avoid the expenditure of hundreds of thousands of dollars on sub- optimal fracture treatments or remedial work.

Gas-Lift Design and Performance Analysis in the North West Hutton Field

Experience at the North West Hutton field has emphasized the importance of properly understanding gas-lift valve behavior. In conjunction with regular downhole pressure and temperature surveys, this has helped maximize production from gas-lifted wells. This paper emphasizes the importance of the downhole temperature survey and of simultaneous well testing with downhole survey work. The paper shows how this kind of performance analysis can reveal such classic problems as leaking valves and such fundamental problems as mandrel spacing that does not match well performance. These analysis techniques also can predict the consequences of increasing available surface injection pressure and have led naturally to the development of more flexible design procedures that optimize production from wells whose performance may be either unpredictable or unlikely to permit a deep point of injection. Field application of these design procedures also is discussed.

Determining the Most Profitable Gas Injection Pressure for a Gas Lift Installation (includes associated papers 13539 and 13546 )

Gas injection pressure has a very decided effect on the efficiency and operation of a continuous flow gas lift well. Selection of a gas injection pressure that is too high can result in needless investment in compression and other equipment, whereas pressures that are too low can cause inefficient gas lift operations and failure to produce a well's full potential. This paper discusses the effect of various producing parameters on the selection of gas injection pressure and describes techniques for predicting and evaluating these effects on a specific gas lift installation to determine the most profitable operating system.

Stimulation Study of Cottage Grove Formation

Bottomhole pressure (BHP) monitoring during hydraulic fracturing treatments can provide data that permit better job control as well as improved design for future treatments. Data collected by this method during a recent study of the Cottage Grove formation in Dewey County, OK, indicated fracture growth through barriers and also tip screenout. This provided a basis for changes in sand scheduling during treatment and in design of subsequent treatment. Stress magnitude in the pay zone and adjoining barriers, rock properties, and fracturing-fluid leakoff coefficients were determined. It is shown that careful analysis of pressure during a treatment can be a useful tool in better design and application of fracturing treatments.

Reservoir Engineering Techniques Used To Predict Blowout Control During the Bay Marchand Fire

Documented here in part are the reservoir engineering techniques used during the Bay Marchand fire. Before any plans for the kill operations were made, a brief reservoir simulation study was conducted to gain insight into the mechanics of fluid flow. Some of the predictions made with the model are compared with actual field results. Introduction A fire broke out on Shells Oil Co.'s Platform "B" at Bay Marchand Offshore Louisiana on Dec. 1, 1970. Of the 22 completed wells (43 zone completions) and two drilling wells, 11 caught fire; and Shell immediately set up an emergency task force to handle the problem of extinguishing the fire and capping the wells. This paper is one of a series that documents the activities of that task force during the 136 days required to cap all of the wells on the platform. Questions To Be Answered The reservoir engineering section of the task force was rapidly deluged with questions, all pertinent and important, for which other engineering sections and management needed answers before they could adequately plan and conduct the kill operations. These plan and conduct the kill operations. These inquiries can be summarized into four basic questions that had to be answered for each of the 11 wells to be capped. (1) What is the possibility that circulation will belost if a relief well were to penetrate a blowoutzone within a 25-ft radius of the producing well? (2) What surface injection pressure can be anticipatedduring a high-injection-rate kill operation? (3) How much water must be pumped into the reliefwell before water breaks through in theproducing well. (4) How much water must be pumped into the reliefwell to achieve 100 percent water production inthe producing well? Techniques Employed Question 1 was easily answered; however, we were not able to come up immediately with simple answers to the remaining questions nor rapid methods of dealing with the problems. Intuition and experience with conventional fluid injection projects strongly suggested that the predominant flow pattern from the injector would be radial, but there was some uncertainty as to the effect of the producing well on this pattern, both before and after water breakthrough. Accordingly, we decided to conduct a relatively brief reservoir simulation study, having a very specific and limited objective: to gain insight into the mechanism involved in controlling a blowout by water injection from an adjacent well. The Reservoir Simulation Study All simulations of a blowout kill operation were made in a two-dimensional areal mode utilizing COMSIMa three-phase, three-dimensional, compressible simulator developed by Shell Development Co. The investigation and its results were all subject to the following assumptions and restrictions: (1) The reservoir was assumed to be horizontal, homogeneous, and isotropic. (2) Interference effects from other wells orreservoir boundaries were ignored. (3) Gravity and capillary effects were neglected. (4) Only the injection of water was simulated. JPT P. 234

Case History of Successfully Water Flooding a Fractured Sandstone

Abstract By 1955, the First Wall Creek reservoir had reached the stripper stage. At that time a 20-acre double five-spot pilot was started to evaluate waterflood feasibility. Injected water was lost from the pilot area through natural fractures, and the five-spots were not encouraging. However, wells outside the five-spots showed production increases, so the pilot area was expanded to include about 100 acres. The expansion proved highly successful, and a full-scale program is now underway. Sand-oil fracture treatments have contributed to the success of the project. Introduction The geology and history of the Salt Creek field, Salt Creek, Wyo., have been described previously. The First Wall Creek pool under consideration here was discovered in 1908 and is one of 11 productive zones found on the Salt Creek anticline. The pool is cut by numerous normal faults of small displacement. Fig. 1 is a field map. Many of the smaller faults have been omitted in this figure. There are surface indications which suggest that some of these faults may be sealed by secondary deposits of calcite. The First Wall Creek pay zone, found at an average depth of 900 ft, is a fine- to medium-grained sand with numerous thin shale partings. Porosity and permeability are locally erratic, and average 15 per cent and 80 md, respectively. Gross thickness of the section averages 120 ft, of which about two-thirds is net pay and the remainder is shale. Core analyses indicate local zones of high permeability, usually near the base of the section. Injectivity profiles from spinner surveys show that extensive natural fracturing is present in some areas, and as a result, matrix permeability does not necessarily determine points of fluid entry into the wellbore. The produced crude is paraffin base, 38 gravity, having an estimated original solution GOR of 550 cu ft/bbl. The northern two-thirds of the Salt Creek field, including all of the First Wall Creek pool, was unitized in 1939, with the Midwest Oil Corp. as unit operator. Pan American Petroleum Corp. conducts the field operations for the unit owners on a contract basis. Sixty-eight companies and individuals are working interest owners in the unit. Gas Injection A gas-drive project was started in the Second Wall Creek pool, Salt Creek's largest reservoir, in 1926. This project was successfulit is still in operationso a similar program was attempted in the First Wall Creek starting in 1927. Maximum available surface injection pressure was only 350 psi, and most of the First Wall Creek wells would not take gas at economically significant rates with this injection pressure, so no measurable production benefit was obtained. Injections were nonetheless continued until 1949 to avoid flaring gas. A total of about 2 billion cu ft was injected in 22 years. JPT P. 1233ˆ

A Field Comparison of Methods of Evaluating Remedial Work on Water Injection Wells

Abstract Since van Everdingen introduced the skin effect concept of determining permeability damage in oil wells, several authors have refined and transformed the analysis for use in water input wells. This paper presents a review of the skin factor determination and its assumptions by the pressure fall-oft and variable rate method of calculation. A comparison with a new evaluation method published by Pan American is offered. Pressure fall-oft data were recorded on 21 dolomite water injection wells prior to and after remedial treatment in the Morse area of the Panhandle field of Texas. Skin factors and effective permeabilities were calculated from these data and from injection rate-time curves. The calculated values of skin in most cases are negative both before and after treatment, indicating increased permeability around the wellbore; however, values of skin effect correlate rather well with injection rates before and after treatment. Values of effective permeability to water calculated from slopes of the pressure fall-off data reflect the low injection rates prior to treatment. Permeabilities after treatment check very well with core analysis permeability data and relative permeability curves for cases examined. Introduction In waterflood injection wells, one of the controlling factors of water injection rates is skin resistance in the area adjacent to the wellbore. This skin may exist for a variety of reasons. Among these are damage caused by drilling mud and filtrates or cement when the well was drilled, paraffin or asphalt deposition in wells converted from production to injection, unstable and incompatible injection water, and swelling clays.van Everdingen recognized the existence of this damaged area in producing wells and presented equations to evaluate its detrimental effect on a well's productive capacity and the effectiveness of remedial work performed on the well. Joers and Smith adapted this work to water injection wells. Others have refined and transformed this original work to other forms such as the variable rate procedure. The application of skin factor determinations as a water flood approaches fill-up and thereafter should be helpful in evaluating the quality of the injection water and point out the needs for improvement in water quality or remedial work on injection wells. Skin calculations which had been run before and after remedial jobs on wells discussed in this paper were used in part to determine the effectiveness of several variables and mechanical changes in order to determine the best remedial treatment for future jobs. Other methods of evaluation were also used since pressure fall-off tests were not available on all wells. These methods are also discussed in the paper. A total of 58 injection well remedial jobs have been performed in the Morse area of the Texas Panhandle field since Jan., 1962. Of this total. skin factors and effective permeabilities to water were calculated before and after treatment on 21 wells. Single skin factor tests were available on nine additional wells. Injection rate-time and pressure-time data were available on all wells. The Pan American evaluation method was calculated where sufficient history after treatment was available for comparison with pressure fall-off data on 12 wells. Effective permeabilities to water prior to and after treatment are presented. Injection Rate-Time and Pressure-Time Curves Injection rate and pressure-time curves or data from which they can be plotted are available on most water floods. These curves such as shown in Fig. 1 are characterized generally with high injection capacity at low surface injection pressures at commencement of injection. They indicate that, as the effective radius of the water bank grows, the injection pressure increases, the injection rate decreases logarithmically and that pressure usually stabilizes before fill-up at the injection equipment limitation. These curves can be used in evaluating remedial treatments in cases such as that shown in Fig. 1. Here, injection pressures before and after treatment were essentially unchanged and injection rates stabilized shortly after the treatment was completed. Where pressures are not stable. a correlation of BWPD injected per psi at the sand face or injectivity index can be used. In most cases, however. more sophisticated evaluation methods are needed. JPT P. 1121ˆ