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.
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.
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.
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.
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.
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.
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.
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.A. demand is expected to grow 2% per annum, the current U.S.A. 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.
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.
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.
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.
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.
The Otter field is the first "dual electric submersible pump (ESP)" completion in the U.K. sector of the North Sea in a subsea field development. This subsea development consists of three horizontal openhole oil producers and two cased-hole water injectors clustered around a production manifold and tieback, 21 km from the Eider host platform. Each oil producer has been able to deliver up to 20,000 BOPD since October 2002. Because a risk of sand production was identified during the life of the field, downhole sand control was deemed necessary.
Well longevity has a major impact on the global-project economics. This meant that achieving and maintaining sand-free production through optimal completion design was critical to the overall success of the development.
This paper describes the strategy adopted and the factors considered in the development of the sandface completion design for the field's life. The sand-control technique had to be decided upon while drilling the well, on the basis of the drill cuttings-particle-size analysis—oversmall particles would have lead to an openhole gravel pack. It appeared that correct geosteering was permitted to stay within a sand body that was adequate for standalone screen completion, which the authors consider the best option (i.e., in cost, risk, and efficiency) when applicable. The operational experience gained and lessons learned on the first well contributed to the design enhancements required for completion of the horizontal wells described in this paper.