A direct comparison of the two most advanced resistivity devices currentlyin use, the MWD based EWR Phase 4TM and the wireline run Array Induction Tool(AIT)TM, is made. Both tools were run in a well drilled off of the East Coastof Trinidad by Amoco Trinidad Oil Company. The tools are run in theirrespective environments to enhance reservoir identification andcharacterization in thin, highly laminated reservoirs. The objective intervalin this area was thought to have this type of reservoir characteristic. Bothuse multiple depths of investigation combined with good vertical resolution todetermine true resistivity (Rt) and to identify invasion profiles. A comparisonof the results of the tools are related to previous efforts with other loggingdevices and actual production results. The two tools are compared through boththinly laminated and thick sand sequences.
Samaan B-8(ST)X well in Samaan Field, offshore Trinidad provides anopportunity to compare resistivity log response between the MWD EWR Phase 4tool and a high resolution wireline resistivity tool such as the ArrayInduction Tool in a thinly laminated sandstone reservoir. Recognition of pay inthinly laminated low resistivity sand sequences similar to the Samaan Field 4BSand reservoir is important in an active exploitation program in this field.The EWR Phase 4 and the AIT obtain resistivity information under differingborehole and invasion conditions. Both resistivity devices respond to thethinly laminated nature of the 4B Sand reservoir.
EWR Phase 4
The EWR Phase 4 (Figure 1.) is a multiple depth of investigation MWDresistivity device that uses four transmitter receiver spacings. From thesespacings, different depths of investigations can be derived using phase,attenuation or a combined phase/attenuation based measurement. The spacingsinclude X-shallow (EWXP, 6-12 inches radius of investigation); Shallow (EWSP,12-18 inches); Medium (EWMP, 24-30 inches); and Deep (EWDP, 36-40 inches). Thethree shallower reading devices propagate at a frequency of 2 MHz, while thedeep reading curve is at 1 MHz.
The Array Induction Tool
The AIT Tool (Figure 2.) is also a multiple depth of investigationresistivity device. It utilizes 8 mutually balanced induction arrays, whosemain coil spacings range from a few inches to several feet3. A singletransmitter coil operates simultaneously on several frequencies between 105 Hzto 104 Hz range.
A new mathematical model for the miscible displacement in fractured-porous reservoirs is developed. A model is obtained by the upscaling of the traditional miscible displacement equations from the scale, which is lower than the fracture opening, up to the scale, which is much larger than the block size.
The model is based on simultaneous use of different mathematical methods: areal averaging of fluid fluxes, asymptotical averaging in systems with periodical heterogeneity, analytical solutions of the problem of interaction between the flux via fractures and the single block. The model takes into account diffusive, gravitational and advective mechanisms of the mass exchange between blocks and fractures and also hydraulic interaction between fluxes via systems of blocks and fractures.
The formula for the modified fractional flow functions which depends on the geometric tortuosity of the system of fractures are proposed. The tortuosity coefficient can be found from the 1-D laboratory displacement data.
The model developed has been validated by comparison with the number of laboratory studies of the miscible displacement in fractured-porous media.
Miscible gas injection into fractured-porous oil and gas-condensate reservoirs is the effective enhanced hydrocarbon recovery method. Nevertheless the efficiency of this IOR method is strongly dependent on parameters of fractured-porous system and on properties of reservoirs and of injected fluids.
The major oil reserves are located in the block system, so the recovery efficiency during the miscible gas injection is determined by mechanisms of the 'fracture-block' mass exchange and by the resulting displacement from blocks.
The displacement efficiency in fractured-porous media with the large opening and the high permeability of fractures and the low permeability of blocks is poor due to the fast breakthrough of the injected gas through the fractured system and low recovery from blocks. For the fractured-porous media with the less contrast between the fracture and the block conductivity the recovery is high.
Nevertheless, the recovery is determined not by the heterogeneity of the fractured-porous system only. If the fractured system conductivity is significantly higher then the one for the block system, but the blocks are small, the recovery could be still high.
The diffusive, gravitational and advective (convective) mechanisms of the fracture-block mass exchange during the two-phase partly miscible flow have been distinguished. The intensity of these three mechanisms are affected differently by the variation of the displacement velocity and also by the viscosity and the density of the injected fluid. Therefore, the comprehensive mathematical model which takes into account all the above mentioned recovery mechanisms is required for the optimization of the miscible gas injection into fractured-porous reservoirs.
Mathematical description of the flow in fractured-porous media are based on the image of the mass transfer in the double-porosity system (two fluxes via systems of fractures and of blocks interact with each other), by G. Barenblatt, Y. Zheltov and I. Kochina. In some other models the flux in blocks is neglected and blocks are treated as the source-sink terms with the given law of the mass exchange.
Another approach is based on the consideration of the fractured-porous media as a periodically heterogeneous media, and the upscaled model is obtained by the asymptotic averaging in periodical systems. The method allows to derive more complex formulae for the fracture-block mass exchange and to obtain the explicit formulae for effective permeabilities for systems of fractures and of blocks.
Diffusive mechanism of the fracture-block mass exchange corresponds to the linear term proportional to the concentration difference in blocks and fractures.
Unreliability with drill stem testing (DST) tools is often experienced by operators in the development of high pressure/high temperature (HP/HT) wells. These environments are normally defined as having hydrostatic pressures of at least 10,000 psi and bottomhole temperatures of at least 300 F. Factors affecting reliability may include deteriorating mud conditions caused by increased depth and temperature ranges, high pressures. which hinder tool operation, and reduced sealing capability resulting from the high temperatures. Solutions to these issues are available, but in many cases, are not used because of insufficient pre-job planning.
This paper discusses a joint project undertaken by eleven major operators and service/testing companies in the Norway, UK area to address these problems and to determine methods that would increase the reliability of DST operations in HP/HT well testing. Emphasis was placed on the selection of the downhole equipment used for the HP/HT DST's and design of the full scale testing of the North-Sea-area field tools in use. Additionally, an investigation was to be made to establish methods that could be used to verify and increase equipment reliability. The project also included design parameters for contingency conditions that were not normally present during equipment operations but could exist in emergency situations.
Eleven tools including tester valves, multiple-cycle circulating valves, bypass valves and safety/circulating valves from different service company/suppliers were rigorously tested. The results of the tests, which compare the susceptibility of various tool design types to reliability problems, will be provided as well as the types of tool modifications that were subsequently made to increase reliability of the equipment for the HP/HT conditions. The data presented will also include results of testing conducted on the equipment modifications.
The method of testing helped determine changes needed to address reliability in HP/HT conditions and has demonstrated that DST tools could maintain integrity in this type of environment.
For over 60 years, drill stem testing has been used to determine reservoir parameters of potential producing zones. However, the early DST applications were traditionally limited to open hole at low to moderate temperatures and pressures. These conditions would include temperatures between 150 and 300 F and pressures ranging from 1,000 to 10,000 psi. With the expansion of offshore DST to cased-hole applications with increased temperature ranges of up to 410 F and increased hydrostatic pressures of up to 15,000 psi, traditional equipment experienced operational problems. These problems included the following in descending order of relative frequency:
1. Mud deterioration resulting from mud remaining static at temperature for several days, either in water-based systems in which the settling of solids caused the string to become stuck in the hole and to create plugs of solids that hindered pressure transmission to the tools, or in oil-based systems that increased in viscosity and gel strength, reducing capability to transmit operating pressures to downhole tools.
2. Tool design that was not fully suited for the conditions. This included insufficient pressure capabilities, especially in the area of air chambers, shear pin-operated tools that were susceptible to pressure and shock from the perforating guns, and string designs that were too complicated for the conditions. For example, several annulus pressure-operated tools run with operating pressures that are too close together because of an insufficiently low pressure test of the casing or liner lap.
Both of the above problems can be minimized with the application of prejob planning.
This paper describes a simple procedure, based in the work of Vogel and Wiggins, to develop IPR curves at any stage of depletion or at any time, for solution gas-drive reservoirs, for two or three phase flow, from results of a Black-Oil reservoir simulator.
In many applications, the use of numerical simulators to represent reservoir behavior would require an excessive computational time. In such a case, one alternative is to use analytical Inflow Performance Relationships (IPR).
One application of IPR is a production optimization method implemented in this work to choose the best value of production parameters such as tubing diameter and choke size. In this procedure, only discrete values are considered and a economic factor is used to optimize an objective function which is the present value of cumulative oil production.
This procedure is compared with the results obtained from simultaneous simulation of reservoir and production facilities which requires much greater computational time.
This work shows: (1) a simple automatic procedure to generate IPR curves from reservoir simulators results, (2) an optimization procedure where only available values of each production parameter are considered; and (3) that dynamic IPR curves that vary with depletion can be used to represent reservoirs in optimization procedures. Problems related to the development of analytical IPR curves are also discussed.
The estimation of individual performance of oil wells can be used to determine, for instance, an optimum method of production, adequate design of artificial lift, success design stimulation, and treatments and forecast of production performance. In many of these cases, the utilization of numerical simulators results in a very high time consumption while IPR curves can be utilized to represent reservoir performance with low computation effort.
Gilbert utilized curves which related flow rate and pressure. He was the first who called them IPR curves.
Weller developed one method to calculate depletion performance in solution-gas drive reservoirs applicable for all saturation conditions considering steady state flow and variable gas-oil ratio.
Vogel presented an empirical method to estimate the pressure-production behavior of oil wells producing from solution-gas drive reservoirs based on reservoir simulator results. He used Weller method to calculate IPR curves with a variety of PVT properties and relative permeability data.
These methods considered only two-phase flow (oil and gas). Brown presented a solution developed in Petrobras to calculate three-phase flow IPR curves. This correlation uses a combination of Vogel type equation for the oil IPR and a constant productivity index (PI) for the water IPR. Oil and water fractions were held constant for all flowing bottom hole pressures.
Wiggins, Russell and Jennings developed analytical IPR curves based on the physical nature of the multiphase flow system. They extended these ideas from two to three-phase flow systems.
In this paper, it is described a simple procedure, based in the works of Vogel and Wiggins, to developed IPR curves at any stage of depletion for solution gas-drive reservoirs using results obtained from a Black-Oil simulator.
IPR curves are used here to optimize production parameters such as tubing diameter and choke sizes. Most of the published work about production optimization, for instance, Caroll, developed non-linear techniques to optimize production performance using some continuous variables. In this work, only discrete values are considered to optimize the objective function which is the present value of cumulative oil production. Therefore, this procedure can be used to optimize several parameters simultaneously with low computation effort.
The development of the mathematical model is based on the following assumptions: (1) homogeneous limited reservoir; (2) reservoir are initially above bubble point pressure; (3) radial flow, (4) Darcy's law for multiphase flow applies; (3) gravity and capillary effects are neglected; (6) isothermal conditions; (7) no gas solubility in water; and (8) fully penetrating wellbore.
This paper presents a new method for determining the effect of well location within any reservoir boundary on well performance. There are several types of analytical as well as numerical methods used to solve potential flow problems in bounded systems. However, these are limited in their treatment of the reservoirs geometrical shape. For two dimensional problems a powerful tool used is conformal mapping. In conformal mapping, a problem is transferred from a geometrical domain in which the solution is sought, to a domain in which the solution is known.
The transformation then provides the solution in the original domain. The practical limitation of conformal maps has always been that they must be computed numerically, except for simple domains where the exact conformal map is known. With improvements in computer technology the method can be used for fast, accurate and flexible computation of solutions to these problems. Traditionally, Dietz shape factors have been used to account for wellbore location within the drainage area. These have been presented for certain well locations in specific geometric domains. However, the technique described in this paper has been shown to be useful in determining solutions to flow problems in complex geometrical shapes, such as flow in fractured horizontal wells, under steady state flow conditions. In this study the basic techniques and their application to simple reservoir geometries will be presented. The results obtained compare closely with results obtained using the Dietz shape factors for certain limited wellbore and drainage area configuration. The application is presently limited to the steady state solution.
For several decades the majority of potential flow problems were solved using several simplifying assumptions and relatively simple geometrical domains. In recent times we have used numerical computing to solve these problems in virtually any domain as well as in three dimensional space. This computing power and expertise has not been wide spread and extensively harnessed. This is in part due to the fact, that most comprehensive reservoir simulators are not simple to use and the cost of such a resource can be prohibitively high, for small operators. Thus, the industry has continued to solve flow problems analytically by continued use of simplified flow domains, modified to account for non conformance from those domains. The objective of this paper is to highlight a technique used extensively in the past, with specific application to solving flow problems in reservoirs, with polygonal boundaries. The method provides some useful insights as wells as ease in solving flow problems for a variety of reservoir conditions, geometries and wellbore reservoir configurations. The method can be described as semi-analytical, since it requires both analytical as well as numerical computations.
Well Inflow Performance Model
The inflow performance model assumes that flow in the two dimensional plane can be extended into three dimensions by combining the two dimensional flow with the effects of flow in the vertical plane using an average reservoir thickness derived from structural contour maps or seismic surveys. The two dimensional flow is solved by use of conformal mapping theory, which guaranties the transformation of all boundary conditions in the physical plane to the mapped plane. A simple flow solution can then be applied to the mapped plane, to determine the flow in the physical plane. This theory has been shown to be accurate in the solving potential flow problems in other engineering disciplines. One of the key uses of this technique is that it is not necessary to have any geometric limitations on the reservoir and wellbore location.
This paper presents an examination of the beneficial effects of aligned-interest alliances on overall project risk. Case studies in drilling and completion services demonstrate how alliances mitigate the risk of project cost overruns through joint planning, superior communication, and a clear understanding of work processes. Successful alliances emphasize common project goals and allow management responsibility for specific well operations and their inherent risks to be passed to the party with the most experience and knowledge.
A distinction is made between project risks (cost, schedule, safety, wellbore integrity) which may be assumed or shared by suppliers and project uncertainties (reserves, oil prices, weather) which should remain with the operator. As with any commercial transaction, prices for services must be linked to the terms under which they are offered. Typically, alliance contracts include bonus and penalty mechanisms. Other alternatives are also discussed. The risk- and reward-sharing characteristics of typical bonus/penalty contract provisions are examined and presented in detail. Introduction
An alliance as defined in this paper is a long-term relationship, founded on mutual trust and commitment, between a service company and an operating company. The focus is on providing benefits for both parties and may include sharing risks and rewards. The cornerstone of any strategic alliance is open communication, which helps lead to a spirit of teamwork among participants.
The term "alliance" is used broadly to describe a variety of relationships. In the context of this paper. however, the term "alliance" refers to substantially increased involvement of contractors in project management roles, such as (1) lead-services contractors or (2) project-well engineering coordinators, during well construction (including drilling and completion), production enhancement, and production maintenance. Such alliances are based on the belief that by combining resources during these phases, operators and service companies can both be more successful.
Formation of aligned interests and achieving a better understanding of the factors that drive additional costs into the suppliers' system are two ways to enhance a relationship beyond that of a traditional arrangement. An essential component of these arrangements is to ensure that all involved parties have a complete understanding of the total system cost as opposed to the price of individual products and services. In addition, a variety of incentive options can be implemented to further optimize revenue, and performance should be measured to help ensure continuous improvement.
The most common types of commercial options available within an alliance approach include the following:
- Lump sum-a fixed price is paid to the contractor. This option ensures project cost certainty but does little to align contractor and operator interests in long-term operating efficiency.
- Incentive/penalty payments-in addition to the price of the job, an incentive is paid to the contractor if the contractor finishes ahead of the original goal, or the contractor pays the operator a penalty amount if the contractor fails to achieve the original goal. This option aligns operator and contractor interests and encourages a team effort. Project success depends on the activities of all parties.
- Payment-related-to-production - the contractor is paid a per-barrel sum based on incremental production. This option aligns operator and contractor interests and provides a form of contractor financing.
It is very important to determine the economical feasibility of a fishing operation in order to know whether to continue or interrupt the fishing procedure. This decision, when erroneously taken, can often lead to unexpected losses of money and time.
In the past the decisions concerning whether to continue or interrupt a fishing operation were based primarily on the operator's previous experience. This procedure often led to wrong decisions and consequently unnecessary monetary losses.
This paper describes the implementation of a decision-making method based on risk analysis theory and previous operation results from the field under study. The method leads to more accurate decisions on a daily basis allowing the operator to verify each day of the operation if the decision being carried out is the one with the highest probability to conduct to the best economical result.
Fishing problems can occur during drilling, completion or production operations in oil and gas wells. These costly and undesirable remedial operations have been resulting in annual losses of US$ 500 million worldwide.
Recently a decision-making method to deal with this problem was developed. Based on risk analysis theory, probability distribution and previous operation results, the method conducts to more accurate decisions allowing the operator to verify if the decision being carried out is the one with the highest probability to conduct to the best economical result.
In Ref. 1, the basic concepts of the method were presented. Also derivations of all equations were presented and thoroughly discussed. Following, a review of the mainly concepts and equations.
- Economic fishing time (EFT): EFT represents, at a certain moment of the operation, the amount of time within the operation should be concluded in order to produce a satisfactory economic outcome.
- Probability of Success: This is the probability that the operation presents to be successfully concluded within the EFT.
- Expected cost of the operation: Value calculated using the principles of risk analysis theory. It involves not only the costs but also the operation probabilities of success and failure at a certain moment.
- Conditional probability of success at day i of the EFT:
- Conditional probability of failure at day i of the EFT:
Experience of Drilling the Horizontal Well VLD-1152 in Lagunillas Formation, Block IV, Lake Maracaibo Basin, Venezuela.
The main objective of the horizontal well VLD-1152, located in Block IV, was to improve recoverable reserves which was impaired by pressure depletion and reservoir heterogeneities. The well represents an important challenge because it is the first horizontal well drilled in a depleted pressure area and it was drilled within a small productive interval of 25 feet thick only.
A pilot area was selected after a detailed multi-disciplinary study by geologists. petrophysicists and reservoir engineers. New 3D seismic interpretation revealed a structural model that conformed well with pressure behavior of the area. New information from well VLD-1112 were utilized to update the petrophysical properties and the volumetrics These data were input to develop improved reservoir description and build a reservoir model for flow simulation.
The results indicated that Layer VII is the most important drainage target. The principal reasons for selecting this unit were, good mechanical stability of the rock, absence of a water front and a secondary gas cap and the presence of a regional shale ar the top that might be used to navigate drilling.
Despite some operational problems encountered in drilling, the results were mostly satisfactory. The entire pay was penetrated and the geology and petrophysics of the drilled area came in line with our model predictions.
A pilot area, containing approximately 30 wells located in Block IV in Lake Maracaibo Basin,was selected as the site for a horizontal well (Fig.1). The target reservoir, VLC-52/VLD-192 Lower Lagunillas, commenced production in 1957 with well VLD-192.
The reservoir, which is stratigraphically divided into L, M and N sands, has not been uniformly drained. Since 1960, most of the wells have been completed in the L and N sands; therefore, the M sand has been less depleted. (Fig. 2) Production declination was very intense and was partially controlled by a gas injection program in 1967. Dropping pressure however continued until getting 1000 psi (Fig. 3)
The drilling of VLD-1112 well at south of the selected area, contributed with valuable information to validate the petrophysical parameters and calculate a new OOIP number which was found to be 20 % greater than the initial estimate of 264 MMSTB.
Once the new geological model and petrophysical parameters were defined, the more prospective area with less operational risk was selected. The output was used as information to develop a dynamic model for the simulator. The results provided well defined boundaries conditions and indicated the absence of an independent aquifer.
The selection of the zone was based on a combined evaluation of different criteria of orientations, lengths and restrictions for the horizontal well. This zone showed low values of porosity and permeability and a depleted reservoir character, justifying drilling of horizontal wells in order to improve oil recovery and maximize the production rate. The recommended location was GOF-3.
The main target is Unit VII of M Sand Lower Lagunillas Member. This sand has an potential of 1200 STBOD, and is expected to have a water cut of 5% and a GOR of less than 1000 SCF/STB.
In order to produce available fluids, pump jacks used at surface have been engineered to stroke as slow as 6 (six) strokes per minute (SPM) and as fast as 14 (fourteen) SPM. Depending on available production, pump length (stroke) and pump size were the only two other variables taken into consideration. This approach works well until a time is reached when production has declined to a point where production inflow no longer matches pump capacity. As production declined, the typical method of compensation was to shorten the stroke, downsize the pump and remain at a constant SPM somewhere around 10 (ten) SPM.
As production declines this approach eventually results in partial pump fill even with small bore pumps, short stroke and slowing the unit as much as possible with current sheave limitation.
At this point it is physically impossible to fit a large enough sheave on the gear box or small enough sheave on the electric motor to reduce the speed below approximately 6 (six) SPM.
On some lower volume fluid production (100 bbls. and less) beam pumping wells it is difficult, if not impossible, to maintain constant production without tagging bottom at all times to keep them from "gas locking". The unit pumps quite well for a few days with the pump spacing set just off "tag" then stops pumping and the string has to be lowered 12-14" to make it pump again. If the string is not raised up again the "tag" destroys the clutch at the top of the pump (fig. 14) and pump life is short with all too frequent parted rods and tubing failures.
By reducing SPM to match the fluid inflow capability of the formation a more constant effective weight can be kept on the end of the rod string (on top of the traveling ball) so the rods don't contract and cause pump spacing to vary.
By reducing SPM according to the available fluid production of a well and keeping a pump efficiency in the range of 60%+ (appendix) erratic rod loads could be reduced or eliminated and production maintained without continually "tagging" bottom. Slowing down like this should prevent excess gas being driven into the tubing. This would eliminate the possibility of the tubing flowing above the pump. If the weight of fluid over the plunger were more constant and rod elasticity was better controlled the plunger would continually return to a preset point at the bottom of the stroke. At the slower SPM more time would be allowed for gas separation to happen in the annulus instead of causing interference in the pump. This would keep the unit pumping constantly with no additional adjustments at surface. Prime mover horse power and amperage draw could be reduced as well. At the same time tubing wear would be reduced and pump run time extended (ref. 2). (By shutting the unit down at the time of pump off; this paper shows better pump run times).
The well chosen for application of the theory came on line at 150 barrels per day and 500 mcf gas then declined to 12.7 barrels per day and 64 mcf gas. A 100" stroke length beam pumping unit was on the well with a 1.5" zero slip pump installed (fig. 14). Other well information is recorded in (table 1) Pumping was very erratic as it continually needed to be respaced in order to make production. Dynamometer cards taken before the slow down were very erratic and unpredictable.
During matrix acidizing stimulation jobs, the use of more acid does not mean more skin reduction during the treatment. The excessive acid volume serves only to dissolve and weaken the matrix rather than remove the damage. The optimum amount of acid needs to be determined in each matrix stimulation case. This is done by calculating the real time skin value which is used to estimate the optimum volume needed.
The acid volume and type used in matrix acidizing stimulation is usually based on the experience of the operator in the field. Trial-and-error or on-site injectivity measurements are used to optimize the acid volume. In order to limit trial-and-error exercises, a real-time on-site treatment evaluation method has been developed to assist the field engineer with a new real-time matrix volume estimation technique. History matching and curve fitting the early stages of the acidizing job, the method determines when the maximum damage removal is obtained and corresponding acid volume.
This work proposes the use of real-time matrix acidizing data in conjunction with real-time skin effect calculations to estimate the optimum acid volume to be used on-site. The results are compared with three acidizing field cases in the paper, but has been verified for sixteen (16) field cases. The method can be used for optimizing acid volume during matrix stimulation in progress and deciding when to stop pumping the acid.
The concept of skin effect has been used as a magnitude of near wellbore flow impairment. The total skin effect is a multi-component quantity including mechanical skin effects such as mud solid and filtrate invasion during drilling and cementing, formation debris during perforation, and fine migration during production. Actually, the skin effect accounts for any deviation from an ideal undamaged, open-hole, vertical well. "Damage" may be caused by a number of phenomena on which traditional acidizing has no effect. Some of these pseudo-damage phenomena are gravel-pack and partial perforation and penetration.
Matrix acidizing stimulation is a treatment intended to remove near-wellbore damage. The determination whether to and how much to stimulate a well and the type of acid treatment should depend on comprehensive pre, real-time, and/or post analysis with high emphasis on quality data gathering. Matrix acidizing job effectiveness can be assessed through real-time or post treatment evaluation of data collected during the acid treatment.
During the matrix acidizing treatment, fluids are injected into the well, causing a pressure response recorded at the wellhead.