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Krekel, Marcus Hendrik (Bluewater Offshore Production Systems USA, Inc.) | Leeuwenburgh, Richard (Bluewater Offshore Production Systems USA, Inc.) | Bishop, William M. (Conversion Gas Imports LP) | Davis, James F. Jim (Paragon Engineering Services, Inc.)
Summary This paper describes the conceptual design of an offshore liquidified natural gas (LNG) import terminal based on the "Bishop Process," sited on Vermilion block 179, offshore Louisiana. The Bishop Process comprises direct regasification of LNG in the dense phase and storage of the gas thus produced in salt caverns. The operating principles of this process are discussed, as well as the design considerations for the regas, storage, and send-out facilities. The single-point mooring (SPM) system for the offloading of LNG carriers is described, as well as the verification process thereof. The foreseen marine operations at the terminal are explained, and the work done confirms the technical and economical feasibility of the concept. Introduction The U.S.A. is currently, by far, the world's largest gas market. Of the current supply, 85% is produced within the U.S.A., and 15% is imported—98% of which is from Canada, and only 2% is in the form of LNG. While U.S. demand is expected to grow 2% per annum, the current U.S. gas production shows an increasing intrinsic decline rate, and more undiscovered gas reserves are needed each year to keep up with demand. E&P operations in new frontier areas (e.g., the Alaskan North Slope) are unlikely to be allowed in the near future, and gradually, the realization is dawning that only large-scale LNG imports can meet the expected demand and stabilize the price of natural gas. In its annual outlook for 2004, the U.S. Dept. of Energy's (DOE's) Energy Information Administration predicts that LNG imports will grow from a modest 0.2 Tcf in 2002 to 4.8 tcf, or a 15% increase, of expected total supply by 2025.1 Although new liquefaction projects for gas are being sanctioned, community concerns, congested ports, security, and cost considerations are seen to frustrate the development of significant increases in capacities to receive LNG, not only in the U.S.A., but also in Europe. This paper describes the conceptual design for an offshore LNG import terminal based on the Bishop Process, which was developed as part of a research project sponsored by the U.S. DOE's Natl. Energy Technology Laboratory. Ten companies, including operators, midstream companies, contractors, and equipment vendors, are participating in this project. The objective of this cooperative research is to design, construct, field test, and evaluate the performance of key components of a salt-cavern-based LNG receiving facility and to describe their application in LNG receiving facilities in the Gulf Coast and northeast U.S.A. Salt-cavern-based LNG import terminals have material advantages over tank-design terminals in capital costs, operating costs, volume of storage, send-out rates, security, and community acceptance.2 Consequently, the abundant appearance of salt formations found in the Gulf region, in combination with hydrocarbon accumulations, enables the concept to have very high potential in this region—not only is the connecting infrastructure to the U.S. gas-distribution system in place, but it is also underused because of declining production, and thus, there is capacity available to handle large volumes of LNG imports. Part of the research study is to further investigate the feasibility of an offshore LNG terminal and to develop the conceptual design for such a facility to such a level that the following can occur:• Exploratory health, safety, security, and environmental studies can be undertaken. • Any possible technology gaps can be identified. • An indicative cost estimate can be made.
Summary This paper illustrates the importance of internal-corrosion-management and -integrity strategy in the development of new offshore-production areas in shallow and ultradeep waters in Brazil, where there is no other production facility nearby. Starting production activities in these areas without any facility—especially pipelines—is a challenge because the investment necessary is high, particularly when the first area to be produced is a gas block. The financial feasibility of a small- or medium-sized gas field with very low condensate production is extremely delicate because this kind of project usually demands high initial investments, particularly with topside facilities, platform structures, and pipelines. The financial scenario worsens as the first investment must consider not only the area to be put into production, but also other potential areas nearby with exploration still under way. To foresee fluid composition and all flow-parameter scenarios is a complex but necessary exercise to reduce risk and keep the operating expenditure (OPEX) as low as possible. One of the aims of this paper is to show one experience in the design of offshore gas fields in the shallow waters of Espirito Santo, Brazil, where pipeline-corrosion management and integrity strongly affected the capital expenditure (CAPEX) and OPEX factors because the flow-rate capacity was overdesigned to transport future production from adjacent fields. This paper discusses some of the newer issues related to the CO2-corrosion-risk-assessment and -integrity strategies. The paper also briefly discusses some current key issues regarding the ultradeepwater fields related to areas of uncertainties caused by internal corrosion, such as pipelines operating under supercritical flow and steel catenary risers operating within a corrosion-fatigue environment. Introduction In recent years, gas and light-/heavy-crude fields were found in new offshore areas in shallow and deep water depths, without any other production facility nearby. This paper discusses how starting production activities in areas without any facility—especially pipelines—is a challenge because the investment necessary is high, particularly when the first area to be produced is a gas block. The life-cycle cost of marginal gas fields with very low condensate production is extremely delicate because this kind of project usually demands high initial investments, particularly with topside facilities, platform structures, and pipelines that should be compensated by the gas-market potential-consumption needs and its tariffs, which are usually low. The scenario becomes more complex as pioneer projects contemplate the opportunity to produce not only the block with known and proven reserves, but also potential blocks in the vicinity with exploration still underway, as we see today in new offshore areas in Brazil and west Africa. These projects are very important because pioneering projects can have a significantly positive effect upon operators' future spending plans. The project should consider, in some cases, building oversized pipelines and separation facilities, while taking into account the opportunity for production of part of the reserves from these vicinities, should be considered. An alternative method often carried out during operations is cutting investment costs, thereby reducing platform structure and topside facilities and sending all production to shore, where treatment facilities are installed under corrosive multiphase flow. This kind of approach is feasible because the most costly item of the project—the pipeline—will still have its integrity preserved. To foresee the outcome (in terms of gas/water composition and holdup, together with all scenarios of gas/condensate-flow rate) is a complex exercise that must be done to reduce the risk of the project, while keeping the OPEX as low as possible. This paper also briefly discusses some current key issues regarding the deep- and ultradeepwater fields related to areas of uncertainties caused by internal corrosion, such as pipelines operating under supercritical flow and steel catenary risers operating within a corrosion-fatigue environment.
Summary Liquid loading in low-production gas wells is a common problem faced in many producing regions around the world. The techniques available to remove liquids from the wellbore impose significant capital and operational costs. This study investigates a new method for unloading and restoring continuous production of low-rate (i.e., stripper) gas wells. The performance of a patented vortex-flow-modifier tool was examined using a 125-ft vertical-flow loop of 2-in.-diameter clear PVC pipe. The vortex device was found to alter the basic flow structure in the pipe, resulting in improved liquid flow. The tool was observed to reduce tubing-pressure loss by up to 17% and lower the minimum gas velocity required to lift liquids up the tubing string. Introduction The production of natural gas is usually accompanied by the production of brine and/or hydrocarbon liquids. These liquids are transported to the surface as small droplets by the natural gas. However, as the reservoir pressure declines, the drag force exerted by the gas is no longer sufficient to carry these liquids to the surface; they are instead held up in the wellbore. Accumulation imposes backpressure on the formation that can significantly reduce the production capacity and can eventually kill the well. A minimum or critical gas-flow rate must, therefore, be maintained to prevent the onset of liquid load up. Numerous authors have offered predictions for determining the critical velocity. Turner1 et. al's correlations are the most widely used. It is based on determining the velocity of the gas that would exert a drag force sufficient to balance the gravitational force of a liquid droplet. That is, [Equation 1] and the expression for the critical gas flowrate is, [Equation 2] It is evident from these equations that liquid unloading can be achieved by,Increasing the gas rate. Reducing the area for flow. Reducing the surface tension or density of the liquid phase. A number of techniques, such as the use of soap sticks, plungers, rod pumps, or swabbing, are available as corrective action to return the well to production. The external interference due to these methods comes at the expense of additional capital and operating costs. In additional to the methods listed, unloading can also be achieved by reducing the pressure drop in the tubing string. This would increase the value of CD, which would translate into more efficient use of the existing reservoir energy. As a result unloading would occur at lower gas rates. Mingaleeva studied the lowering of pressure drop in self-twisting helical flow. He observed the mechanism from an energy standpoint, and concluded that the liquids and gases will flow through a path of least resistance. Also the power spent to overcome the hydraulic drag for raising an air column in a helical trajectory, was compared to the motion and rising of an equivalent air mass at the same velocities by a straight column, was significantly lower. Therefore he concluded that the helical path was more favorable from an energy-use viewpoint. As a result the air column suffered a lower pressure drop when it moved in a helical path. This paper examines the use of a flow-modifying device that creates a helical flow to unload liquids. Laboratory experiments were conducted using a 125-ft vertical flow loop on 2-in. diameter clear PVC. In these experiments, the effects of gas and water flow rates on the flow-modifying device were considered and compared with the behavior in normal pipe flow.
Summary Foam stability is an important parameter for foam fracturing. Bench-top testing is useful for screening but does not address the necessary conditions of temperature, pressure, pH [particularly with carbon dioxide (CO2) systems], and dynamic-flow conditions that can have unexpected influence on the foam's performance. A laboratory apparatus has been constructed for measuring the rheology of circulating-foam fluids to 400°F and 3,000 psi. The apparatus is equipped with a circulation pump, view cells, foam generator, mass flowmeter, and piping for loading a foam of the desired quality using either nitrogen (N2) or CO2. The foam rheometer is intended for evaluation of foam stability with time and comparison of various foam formulations for application in foam fracturing. The foam loop was designed to mimic shear rates found in a fracture or reservoir, which are typically 200 s-1 or less. The rheology is measured by monitoring the pressure drop across a 20-ft length of ¼-in. tubing maintained at temperature in an oven. Flow rate is continuously adjusted, to ensure a constant shear rate in the tubing, by the software using continuous mass-flowmeter input. Results relating to CO2 and N2 foams are discussed with emphasis on foam persistence, bubble size and population, and the rheological behavior with time. Temperature, pressure, and additives affect both foam texture and foam stability. The adoption of a standard technique patterned after this work for evaluating foam rheology could impact the use and development of foam fluids in the future. Introduction Foam-fracturing fluids are used in approximately 40% of all fracturing-stimulation treatments executed in North America. Foam-fluid functional properties, such as proppant-carrying capacity, resistance to leakoff, and viscosity for fracture-width creation, are derived from the foam structure and the external phase properties. Moreover, the foam must have structural stability to maintain its performance throughout the treatment. A major objective of this work was to develop an efficient method of evaluating the time-dependent properties of foam-fracturing fluids under meaningful conditions. The reasons for this objective are to evaluate the effectiveness of surfactants and to determine the two engineering parameters, behavior index (n') and consistency index (K'), used by fracturing simulators to estimate treatment operating parameters and fracture geometry.
Summary It is commonly observed that hydraulically fractured wells perform as though the "effective" fracture half-length is much lower than the designed half-length. This observation has been explained by various models, including poor fracture-height containment, poor proppant transport, proppant falling out of zone (convection), ineffective proppant-pack cleanup, capillary-phase trapping, multiphase flow, gravitational-phase segregation, and non-Darcy flow, with combinations of any of these mechanisms. With recent improvements in diagnostic measurements of fracture geometry, some of these explanations have lost credibility, but the problem of low effective fracture length persists. This paper presents detailed evaluations of hydraulically fractured well behavior with continuous production analysis, pressure-transient (buildup) analysis, and fracture-treatment evaluation by use of actual field data from a tight-gas reservoir in the Rocky Mountain Region. The various analyses explain the observed producing behavior of the well and lead to a consistent determination of the actual effective fracture half-length compared with the physically created or propped length. Problems relating to semantics and inconsistent fracture and reservoir description, especially the physical processes encompassed by various analytical techniques, will be addressed. Methods will be outlined for predicting the useful effective length from available proppant-conductivity data. The process outlined helps to close the gap between designed-fracture and producing lengths and points out the causes for the remaining system bottlenecks that limit post-fracture well productivity. Finally, the understanding of these mechanisms provides a means to arrive at an economical optimum fracture-treatment design for a reservoir once key parameters are known. Introduction The comparison of fracture-design lengths to actual well performance can provide valuable insight into the effectiveness of the fracture stimulation. This process requires the effective integration of several analytical tools. The evaluation process starts with the prestimulation design and ends with an evaluation of the well's production performance. The actual rate and pressure response from the stimulation should be history matched to determine the effective fracture half-length. The resulting length should then be compared to both the prejob estimates and actual well-production performance. Several analytical techniques are currently available to perform post-production analysis, including pressure-transient testing and production analysis. Production analysis is a technique that incorporates the well's rate and flowing pressure into a type-curve-matching process to provide a consistent post-stimulation analysis. The resulting well performance can then be evaluated by comparing the well's producing capacity with its actual performance. The evaluation of past performance has proved to be the best method of improving future performance. In many cases, the resulting fracture half-length calculated from post-production analysis is much shorter than planned. This discrepancy can be a source of contention between the team responsible for completing the well and the team responsible for the optimization of field performance. Frequently, these discrepancies can be quantified through a comprehensive, consistent analysis of the available information. Identifying the problems that result in short effective fracture lengths allows appropriate design changes to be made to improve future well performance. The example-well case histories described represent a subset of a more extensive field study. In general, the study identified the need for a change in the stimulation design in the field, which has been successfully implemented and has resulted in significant production-performance improvements.
Summary With the increase in operating costs and the need to withstand the cyclical swing of the oil prices, there is a growing demand for cost-effective production operations. Challenges associated with extreme depth, pressures, and temperatures at which corrosion is a problem can translate to additional problems caused by tubing burst, collapse, and tension. Tubular goods subjected to corrosion suffer strength deterioration. This becomes detrimental when coupled with cyclic loading. Failure of tubings could lead to disastrous consequences and the loss of the well, and if tubing strings are not designed in consideration of corrosion effects, it could also result in problems that will require well-control operations. Stress concentration caused by corrosion cavity plays an important role in tubing design under corrosive environment. The objective of this study was to develop a new criterion for designing corrosion-resistant tubular strings in deepwater and ultradeep high-temperature/high-pressure wells. This paper presents results of our theoretical investigations of the corrosion effects on tubing-strength degradation. A new method and a revised criterion have been proposed to predict the threshold pressure for degraded tubing strength. Analytical formulae have been developed for calculating stresses around semispherical cavities, shallow surface cavities, and deep spherical cavities in the body of tubular strings. The effects of stress concentration on tubing strength are analyzed with these formulae. Solutions are also presented in the form of plots that can be easily used by the production engineers. An application example is presented in this paper. Introduction Corrosion pits act as stress risers and decrease the pressure integrity of tubing, resulting in tubing failure. There are many references that sought to quantify the design of tubing subjected to different loads during production operations. Comparatively little research has assessed the effect and integrity of the tubing strength on the basis of the corrosion pits' geometry shapes and dimensions. Thus, it is highly desirable to predict the extent of stress concentration caused by corrosion-induced pits and cavities for both the designing and evaluating processes. Schmitt et al.1 experimentally studied the localized corrosion caused by erosion and pitting corrosion. The induction period and the effects of the precut grooves on the localized corrosion were studied. They analyzed the cause and effect of the pitting and corrosion during sweet-gas production and presented methods to inhibit the attack. Pitting corrosion studies indicate that pitting corrosion is a localized form of corrosion by which holes are produced in the structure wall.2–11 Pitting causes localized attacks on the tubing and is one of the most destructive forms of corrosion. The loss of weight because of pits is much lower, thereby making it difficult to detect the intensity of pitting corrosion. The initiation period of pitting is long, and, once initiated, the rate of pitting increases at a much higher rate. The loss of weight caused by pits is most likely to occur in the presence of chloride ions, combined with such depolarizers as oxygen or oxidizing salts. Small scratches, defects, and impurities in the steel pipe wall can initiate the pitting process. Mechanism analysis has shown that, because pits can be either hemispherical or cup-shaped apart from the localized loss of thickness, corrosion pits on the tubing wall can cause severe local-stress concentrations if the tubing is subjected to loads. The most damaging load for tubing is the burst load. Burst loads to the well tubing originated from the column of production fluid that holds a very high pressure and acts on the inside wall of the tubular structure. Even though the tubing is initially designed with proper safety factors, the change in the loading condition during the life of the well may lead to bursting of the tubing because of degradation of the tubing strength caused by corrosion. If the tubing strings are not properly designed, it may result in a tubing burst and, thereby, blowout and loss of the well.12
Summary To date, most of the research concerning the separation process has had a deterministic approach because of its orientation to steady-state-flow regimes. However, this assumption is far from true when many artificial intermittent gas lifted (IGL) wells are connected to the same separator. IGL wells have flow/no-flow periodic conditions associated with long accumulation stages and short production stages lasting approximately 20 minutes and 1 minute, respectively. A stochastic algorithm was developed to simulate the separation process and the proper periodicity of each IGL well, along with the unpredictable delay or synchronization between those wells. The simulation couples the dynamic mass-balance equations in the separator and the Monte Carlo method for predicting the gas and liquid rates associated with the superposition of the IGL wells. The input parameters for this simulation include daily gas/oil production and cycle time of each well, the oil properties, separator pressure and temperature, and the control scheme. The simulator output matched with less than 10% of the field data. The results obtained with the approach suggested in this work could be used for new criteria in design, simulation, and evaluation of separation facilities under fluctuating conditions. Introduction Separation is one of the most common and important operations at surface, because high separation efficiency is fundamental for posterior gas and oil processing. The separator consists of a recipient that re-collects the production of the wells connected to the production manifold. Separators are designed and sized for handling steady-state flow, and their control schemes usually consider the fluctuations expected in steady state. At this point, the order of magnitudes involved must be highlighted to realize the problems faced in this research. Fluctuations in steady state associated with slug-flow pattern refer to instantaneous changes between 2 and 4 times the average rate of 1, and slugs every 1 to 10 seconds. On the other hand, IGL wells have a long accumulation stage and a brief lifting or production stage, which means a flow/no-flow condition at the surface. Therefore, IGL fluctuations refer to instantaneous changes between 50 and 100 times the average rate (daily production) for a short time—every 30 minutes. Obviously, when IGL wells are flowing into a separator, those design and control schemes for steady state are no longer suitable. The main objective of this work is to develop a new algorithm to simulate a vertical separator on the basis of a new approach that considers instantaneous mass balance, separator-control schemes, and stochastic behavior of the synchronism of the IGL wells while keeping their periodicity. Previous works by Schmidt,1 Giozza,2 and Genceli3 consider the transitory effects in the separator through the estimation of the liquid in the slug-flow regime. The contribution of the present work is the establishment of a new simulation approach for vertical separators working with IGL wells, which improves the criteria to design and evaluate vertical separators. This work focuses on simulation and evaluation only, so no facilities or control strategies are discussed. The major assumptions of the paper include the following:• The gas is separated at the bottomhole during the accumulation stage. • The fluids are considered to be black oil. • Gas/oil interfae in the flowline is sharply defined. In addition, the model must be able to run with standard field data (i.e., gas/oil rates, well pressure charts, fluid properties, and separator configuration) because those are the main variables that define the dynamic behavior of the system. Model validation consists of matching real field data with model results; the field data come from a separator from Lake Maracaibo, which handles 28 IGL wells.
Summary Several horizontal wells have been drilled in different sandstone formations in Sumatra. These formations have a typical permeability of 100 to 500 md, a low bottomhole pressure (BHP) of 450 to 750 psi, and a bottomhole temperature (BHT) of approximately 200ºF. The wells are completed with a perforated liner. The objective of the horizontal-drilling program was to increase oil recovery in low-permeability estuarine reservoirs. Some of the drilled horizontal wells did not perform to expectations, and an intensive study was undertaken to identify completion and stimulation opportunities to increase production. During this study, all aspects of the initial completions were examined and redesigned. The drill-in mud was reformulated to reduce the amount of polymer and increase the use of fine calcium carbonate to decrease lost circulation during drilling and to simplify the removal of filter cake during initial completion. Core tests were performed to identify the optimum fluid formulation, which dissolves the remaining filter cake but does not destroy the formation's natural permeability. A new way of removing the filter cake after completing the well was introduced using oxidizer technology. A new, true-fluidic oscillator (TFO) was used to remove near-wellbore skin (in conjunction with an improved acid system) for wells that have been producing for several months or years. The paper presents several case histories to discuss how completion and stimulation problems were systematically evaluated resulting in increased horizontal-well production. Introduction Oil- and gas-producing companies have been greatly interested in horizontal wells because their increased inflow area provides the potential to produce more oil and gas compared with vertical wells. The history of horizontal wells goes back as far as 1947.1 In the last two decades, the industry intensified efforts in exploring the potential of horizontal wells and overcoming many challenges that are particular to this type of completion. The advantages associated with horizontal wells have been identified by several authors and can be summarized as follows 2-4 :• Maximizing reservoir exposure. • Targeting multiple zones. • Exploiting thin pay zones. • Reducing drawdowns to minimize premature water and gas coning. • Improving production rates and increasing recoverable reserves. The three types of horizontal-well completions are openhole completions (with and without perforated or slotted liner), openhole completions with screens in place (with or without gravel pack), and cased-hole completions (also called stimulation completions).5 The decision of which completion to use depends on the specific reservoir characteristics.3 Cased-hole completions offer the advantage of simpler workovers and the option of specifically designed stimulation treatments. Furthermore, perforating the liner after cementing it in place can ensure that mud filtrate or invasion is bypassed. Consequently, these completions are more expensive and include challenges, such as obtaining an efficient cement placement along the entire interval for effective isolation and designing an effective perforating strategy. If sand control is an issue, then screens and prepacked liners are commonly used to avoid sand production (with or without gravel packing). Challenges in this case are associated with avoiding plugging the screen with mud and drilling solids and ensuring that the entire interval is producing to avoid hot spots, which could introduce local erosion of the screen.6 If the zone of interest is a consolidated formation that is not susceptible to formation collapse, then an openhole, or barefoot, completion becomes attractive. The disadvantages of a barefoot completion include the limited ability to perform workovers in certain areas in case water or gas breakthrough is observed. This becomes a significant problem in sandstone formations in which the high frictional force between the interface of the formation and coiled tubing does not allow coiled tubing to enter to a great depth. This challenge can be overcome by deploying slotted or preperforated liners plus external casing packers (ECPs). Optimum production results for openhole completions, with or without a preperforated liner, can be achieved by using a specifically designed drill-in fluid (DIF) then effectively removing the mud filter cake formed by the DIF. Both areas have been studied and discussed by Morgentaler et al.,7 Browne and Smith,8 and others. These studies found that 100% effective removal of the filter cake in horizontal openhole wells is not necessary because of the large inflow area. In fact, Browne and Smith concluded that if the permeability reduction is less than 70%, then the productivity of the wells does not fall significantly. Furthermore, they identified that the permeability of the mud filter cake has only to be increased to 0.1 md from approximately 10–5 to 10–8 md to achieve the same productivity as complete removal of the filter cake. Thus, 100% removal of the filter cake may not be a necessity and the optimum design should take this fact into account to identify a mud-removal design that meets the economic feasibility of the well. For horizontal wells that have been produced for a period of time and experience a production decline, the challenge is not to remove the mud filter cake but to identify where the damage is coming from and how to remove it. Common causes for production decline include depletion, scale buildup, paraffin and asphaltene dropouts, fines migration, and others. Thus, for older wells, the most important issue is identifying the damage and designing a treatment accordingly. For each particular well, an engineered solution should be designed involving problem identification, fluid-compatibility studies and core analysis, completion design (e.g., placement9 and unloading procedures), and more.
Summary The scale-control challenges for two North Sea carbonate reservoirs are reviewed in this paper. While carbonate reservoirs are not the largest source of hydrocarbons within the North Sea, they are very significant on a global basis. The mechanism of scale-inhibitor chemical retention observed for phosphonate, polymer, and vinyl sulfonate copolymer (VS-Co) inhibitors on carbonate-reservoir substrates is outlined. Chemical placement represents the most significant technical challenge when performing scale-inhibitor squeeze treatments into fractured chalk reservoirs. Examples from more than 50 field treatments applied in reservoirs E and V, in which both phosphonate and VS-Co chemicals have been deployed, are used to illustrate the difference in chemical retention observed in laboratory evaluations. The laboratory studies demonstrated clear potential for significant extension in treatment lifetime by changing from a phosphonate to a VS-Co-based scale inhibitor. The selection and qualification of chemical-placement systems for deployment of inhibitors in fractured carbonate reservoirs are also outlined. To this end, novel technologies to enhance conventional scale-inhibitor-chemical placement are vital to economic success during waterflood projects. Introduction The correct selection of scale inhibitor for the control of mineral scale within reservoirs and associated production tubing is vital if economic hydrocarbon production is to be maintained. The following section outlines the principle differences between carbonate and sandstone reservoirs, which make scale-inhibitor selection and application a technical challenge. What is Carbonate? Carbonate reservoirs are principally composed of carbonate minerals, which include calcite (CaCO3), dolomite (Ca, MgCO3), ankerite (Ca, Mg, FeCO3), and siderite (FeCO3). Carbonate reservoirs can be sub-divided into chalk and limestone. Chalk reservoirs are composed of small spherical/plate-like particles (cocoliths) of calcium carbonate from the skeletons of marine organisms, which became compacted and cemented to form rock with a higher primary porosity - this is shown in Fig. 1. Limestone is generally formed by the deposition of fine carbonate mud with associated fragments of biogenetic material (shells, etc) which is compacted to form rock.1,2 Such a limestone reservoir would generally have a low primary porosity but a high secondary porosity owing to the dissolution of some of the rock caused by reaction of pore fluids during burial. Fluid Flow in Carbonate Reservoirs Flow within carbonate reservoirs generally occurs as a result of fluid flow within fractures (both natural and induced), which enhance production. The fluid flows first through interconnecting pores, and then, along the fracture paths to the well bore. The pores formed during sediment deposition are generally poorly connected within carbonate reservoirs resulting in a lower permeability/porosity ratio than for sandstone reservoirs. The deposition of scale, both carbonate and sulphate, within carbonate reservoirs results in a decline in total production rate, with the fractures becoming restricted owing to the deposition of scale as a film. In the smaller fractures, the deposition and restriction of flow could be associated with the migration of scale particles which block, or reduce, fluid paths. Mechanical or acid generated fractures can sustain a significant amount of damage (95% of the fracture face not contributing) before the fluid production from such a well is significantly impacted.3
Noonan, Shauna G. (ConocoPhillips Co) | Kendrick, Michael (Chevron Energy Technology Co) | Matthews, Patrick (Chevron Corp.) | Ayling, Ian (Centrilift) | Wilson, Brown Lyle (Centrilift) | Sebastiao, Nelson (Chevron Corp.)
Summary Chevron Corp. has 13 wells producing offshore Africa with electric submersible pumps (ESPs) that experienced problems primarily caused by the transient nature of the multiphase inflow through the sinusoidal-well profiles. A study completed in 2002 used a transient multiphase simulator to model the sinusoidal sections of each producer and to calculate the conditions that the ESPs could see over the life of the well for various drawdown conditions and speeds. This paper focuses on how the results from the simulator were validated and used to reduce operational downtime and improve future ESP completion designs. This paper also will demonstrate how severe sinusoidal-well profiles impact production operations. Introduction The Banzala field, located in Block 0, offshore Cabinda, Angola, has 13 wells that have been producing with ESPs since 2000. In 2002, it was observed that the declining reservoir pressures and rising gas/oil ratios (GORs) were adversely affecting production. The ESPs would frequently shut down because of low amperage. Because this was an unmanned platform, the associated downtime was significant. The engineering staff associated with this property wanted assistance in modifying the equipment or well designs to get optimal performance from the ESPs. All these wells were drilled as sinusoidal horizontals or multilaterals. Because of the presence of a shallow gas hazard, it was necessary to place the well jacket on the flank of the Banzala structure, necessitating world-record high-angle drilling to intersect the reservoir.1 As the reservoir inflow began to decline, so did the fluid velocities in the horizontal sections. As a result, gas bubbles started to coalesce and accumulate in the high spots within the undulating wellbore. Accumulation continued until the pocket of gas bridged the hole diameter, eventually being forced out as a slug, and the process continued to cycle. It was assumed that when the larger gas slugs reached the ESPs, the amperage would drop below the minimum allowable set in the surface control panel, and the power to the ESP would be shut off. Traditionally, studies such as this would begin by using a standard nodal-analysis program to evaluate the inflow. The issue with these programs is that they are static models, and the parameters that needed to be evaluated for this project were dynamic in nature (i.e., size and frequency of gas slugs). At the time of this study, there did not appear to be any dynamic multiphase functions available in commercially available nodal-analysis software. However, Chevron Corp. uses a transient multiphase simulator2 for analyzing flow behavior in risers and flowlines on most of its deepwater and subsea developments. Because these sinusoidal-well profiles bore a resemblance to a flowline profile, it was decided to use this program to model fluid-flow behavior in these wellbores. The principal aspects of work performed during the study included using a transient multiphase simulator to model the sinusoidal/horizontal hole section of each producer, calculate the current conditions (e.g., frequency and volume of gas slugs), and then perform a sensitivity study to determine what might be done to alleviate any slugging problems found. The results from the transient analysis were then used to develop optimal ESPs and completion designs for existing and future wells.