This paper demonstrates a work flow to determine optimal lateral lengths and trajectories in the Midland Basin by studying the effect of the lateral length and trajectory on well production.
Forecast expects continued multiphase flowmeter growth | Oil & Gas Journal
Operators often use a scalar to determine wellbore contributions for wells with an atypical lateral length on their leases. The work flow presented here provides realizations to justify use of this scalar, evaluating whether lateral lengths proportionally increase production, whether wellbore contributions are uniform throughout the lateral length of the wells, and whether various wellbore deviations and tortuosities should have the same scalar applied for estimating well production.
A team investigated the effect of lateral length on well estimated ultimate recovery EUR. The EURs were calculated from daily production data from 15 operators and then normalized by well lateral length from the top perforation to the bottom perforation. The modified hyperbolic method was used to perform the decline-curve analysis. Simply applying a scalar for the lateral length among the wells would not yield proportionate EURs.
When drilled and completed in unconventional reservoirs with multiple-stage hydraulic fracturing, horizontal wells experience a decline in productivity with time because the conductivity of those man-made fractures deteriorates with production and time. Therefore, in order to understand the effect of wellbore trajectory and lateral length on production fully, the team developed a work flow to incorporate an in-depth analysis on transient effects of wellbore hydraulics combined with unconventional reservoir performance over time.
Metadata Show full item record. Abstract Drilling, or gas kick, simulators are becoming prevalent in industry due to their ability to replicate wellbore conditions that are not feasible in a laboratory setting. This is becoming more desirable as deeper wells are being explored. One of the biggest dangers that could happen during drilling operations is the onset of a gas kick. This occurs when a zone in the formation whose pressure is higher than that of the wellbore is breached.
This allows for the undesired influx of formation fluids into the wellbore. If left uncontrolled, it could develop into a blowout. Gas kick simulators allow for testing of procedures that could be used to contain kicks at such depths. Furthermore, the use of drilling simulators could provide more insight into other phenomena.
These include wellbore breathing and fracture ballooning, that cause similar kick symptoms at the surface and lead to expensive misdiagnosis, and the dissolution of gas into oil based mud, which could delay the identification of a kick. It is clear that the necessity of gas-lift, optimal operability and system design should be assessed from various aspects, including flow assurance.
Deeper points of gas injection at higher injection pressures are required to achieve desirable liquid production rates 2. Robust gas lift equipment that has been dynamically tested for endurance, integrity and reliability including: liquid flow erosion testing, high volume gas injection testing and gas injection performance. Work-over at Subsea wells are costly. Improved gas flow geometry stabilizes liquid production increasing the run life of the system. The cost of intervention in a subsea well is considerably higher than for a traditional completion. Port size of the operating valve a Too large a port may en-courage unstable lifting conditions.
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Other considerations such as: a. Gas-lift Injection Location b. Source of lift gas c. Available pressure and temperature i. Water depths e. Production rates f. Tubing sizes g. Temperature profiles i. Special metallurgy j. Flowline Pressure i. With and without gas lift ii. Dead oil filled k. Cool down time considerations l. Consider all credible scenarios 4.
Develop a set of scenarios that will encompass the likely well performance over the life of the well 2. Review the Base Case reservoir model. This reflected the possibility that a Water Injection well could be added to the reservoir several months after 1st oil and that it would be justified by the initial performance of the lone producer.
Analyses the pressure profile studies of the well during the early life, midlife and later life of the field. Establish appropriate sensitivity variables a. Reservoir Pressure. Water Cut c. Gas Injection Rate 5. Production Rate Range b. Depth of Injection Range c. Gas Injection Rate Range 4. Oil systems 1. Low GOR 3. J-T cooling Effect if any 5. Downhill flowlines 6. Some Uphill flowlines 7. A subsea well consists essentially of a wellhead assembly and Christmas tree sometimes referred to as a wet tree , which is basically identical in operation to its surface counterpart, with the primary exception of reliability refinements, to permit operation at the seabed.
Well drilling or intervention requires vessels such as jack-up rigs or semisubmersibles b. Reservoir fluids are generally tied back to a host facility for processing and export c. Utilities, control, and chemicals are supplied from the host facility via umbilicals Subsea wells have been used in support of fixed installations as an alternative to satellite or minimum-facility platforms for recovering reserves located beyond the reach of the drill string or used in conjunction with floating systems such as FPSOs and FPSs.
Figure: 19 Subsea field developments. A few specific flow assurance issues are discussed below. The full scope of flow assurance is shown in Fig. Flow assurance matters specific to subsea tieback systems are shown in Fig. Figure: 20 Full scope of flow assurance Figure: 21 Flow assurance matters for subsea tieback systems It is necessary for sufficient pressure to be available to transport the hydrocarbons at the required flow rates from the reservoir to the processing unit. Matters that require consideration in this regard include pressure loss in flowlines, separator pressure setpoint, pressure loss in wells, artificial lift method selection, remote multiphase boosting, drag reduction, slugging in horizontal wells, gas lift system stability, and interaction with reservoir performance.
Components and systems should be designed and operated to ensure that flowrate targets are achieved and that flow is continuous. Issues to be taken into account include hydrate formation, wax deposition, asphaltenes, sand and solids transport, corrosion, erosion, scale deposition, interaction of slugging and pipe fittings, interaction of slugging and risers, relief and blow-down, pigging, liquid inventory management, and well shut-in pressure.
For multiphase flowlines, it is necessary for the process to be able to handle the fluid delivery, and consideration should be given to a number of issues including interaction with facilities performance, slugging steady state , slugging transient , slug-catcher design, severe slugging prevention, effect of flow rate change, temperature loss prediction, piping layout, remote multiphase metering, gas and dense phase export, oil and condensate export, and separator performance. The need for well testing and overall production system optimization contributes to flow assurance issues.
Significant advances have been made in this field. Flow assurance will continue to remain critical technology as deepwater developments progress and as longer tiebacks from subsea wellhead systems are considered. Gas lift has several advantages which can be applicable for increasing production. Here are some few cases such as T field East Malaysia where gas zone is present at the top of oil zone and this gas is used to lift the oil from the well bore to the surface by using a Auto Gas Lift Valve with Hydraulic control operated from surface; Block 6, Sudan, in this case heavy oil is lifted from a well using gas lift using condensate gas, injected into the reservoir prior to the gas injection; Single Point Gas Lift System, in this case only one gas lift valve is installed to reduce the unloading valves which will become potentially leak path; In wells with long perforation intervals cause insufficient velocities below the packer can cause liquid loading.
Injecting the gas below the packer to maximize the production. The cases that are discussed below are referred from published papers. T field has old platform with limited space and is not economically feasible to place gas compressor. As a part of development program four infill drilling wells were drilled in order to achieve the target recovery. From geological and drilling perspective, in order to maximize the well contact with planned oil section sands, two trajectories were designed to penetrate both top gas zone and bottom oil zone. The target sand has a clear dipping structure with an over laying gas zone followed by long section thin oil bearing zone.
As earlier mentioned oil bearing zone at the bottom has weak water drive. To get more contact with the target oil bearing zone, the well trajectory was placed to touch a short section of gas zone at the top and penetrate the whole long section of thin oil bearing sand along the dip until real time logging while drilling petro-physical logs detect a clear oil water contact. Figure: 22 field proposed well target sand structure map and an infill well trajectory In this field a gas zone is present above or below the oil zone of same well, which can be utilized to lift the oil from the wellbore.
A novel Smart Auto Gas Lift AGL downhole system that utilize gas from the gas cap or gas zone present at the same well to lift the oil from wellbore. The value of auto gas lift valve was easily demonstrated as it provides a direct replacement for conventional gas lift equipment with surface controllable downhole valve for optimal gas injection and well lifting design.
Smart AGL valve i. The rate of injection from the gas zone was controlled by a AGL valve through a hydraulic control line from the surface. Both the oil and gas zones are isolated by placing a packer in between the zones. Fig: 22 Proposed smart AGL completion configuration for the T field To determine the feasibility of AGL completion a nodal analysis using single well model was performed for all the four wells to evaluate the strength of the gas zone pressure and make sure that this pressure is sufficient to inject the gas into tubing to lift the oil efficiently.
To understand the target oil zone based on the offset wells, the productivity index model was selected to minimize sand property uncertainty. To capture the uncertainty of gas zones PI and sand properties, a Pseudo steady state analytical model was selected to characterize sand quality that was indicated by well petro-physical logs and sensitivity analysis also conducted on gas zone pressure depletion, permeability, net thickness, mechanical and skin factor.
From these quick studies two out of four wells are selected based on the main gas zone pressure support for continuous nature gas for entire production life of the two AGL wells.
Figure: 23 Single well nodal analysis for quick candidate screening Single Well Dynamic Simulation for Time Lapse Value Justification: Dynamic simulation and Local Grid Refining characterize the multi zone heterogeneities methods take long time to run simulation for the wells. For this case a novel single well dynamic simulation was applied to evaluate time lapse production upside between different completion methods.
To create this, the work starts by populating near wellbore zonal sand properties from synthetic petro-physical logs which can be extracted from full field geological model and the minimum resolution of log data is applied to capture the heterogeneities of multi-sand layers. After property construction, the zonal layer fluid model, zonal pressure and contact initial conditions and zonal sand real perm scale data should be properly defined for each layer.
An advanced completion modeling method should be used to model one smart AGL valve at top gas zone and to select either an open or sand alone screen completion for bottom oil zone or to involve another smart downhole flow control valve FCV to produce bottom oil. Figure: 24 Construction of single well dynamic simulation model The performance of each possible completion strategy, various cases were simulated with constructed single well dynamic model.
These openings can be flexibly changed through a hydraulic control line from surface. In order to make sure AGL works properly through entire life of well, these designed openings should be further optimized to site for changing reservoir conditions and this optimization can be conducted by a specialized nodal analysis method. The single well nodal analysis model at initial reservoir conditions acquires same model used as discussed in figure.
This model changes due to reservoir dynamic conditions over time need to be manually updated in terms of pressure depletion, water cut increase and GOR increase based on single well dynamic modeling outputs.
mail.wegoup777.online/amor-amor-amor-tres-relatos-romnticos.php For an effective result noel analysis is performed at three different times, i. Therefore a smaller intermediate AGL valve opening position will be effective to apply for this initial production condition shown fig. At this stage liquid column will be heavier in production tubing, a slight change in the AGL valve opening position is require to optimize high injection rate for lifting. At late stage of production, the reservoir pressure is further depletes and even larger port size opening should be optimized and applied for high injecting gas rate.
Sensitivity analysis was then performed from these nodal models on zonal layer properties to analyze for any uncertainty such as zonal PI or permeability, skin, GOR and water cut shown in fig. The sand face was completed by sand alone screens using swell packer to isolate the gas and oil zones shown in fig.
AGL valve is installed at m with dual hydraulic control line to surface provides the ability to adjust the port size without well intervention and a balanced operating configuration. The installation depth was critical for efficient AGL operations from the production modeling. The dual pressure and temperature gauges were installed on a single permanent downhole cable to provide tubing and annuals pressure and temperature throughout all phases of the life of the well.
Other completion components include the safety valve, 10 side pocket mandrels, sliding sleeve for circulation of completion fluids, production packer with control line feed through ports, X-nipple, blast joint installed across the gas zone and a seal assembly for isolating gas and oil zone inside the screen. High level quality control test was performed before installing in the offshore. The completion was run in hole as per the approved completion program and tubing tally to ensure correct depth positioning of the AGL valve and location of the seal assembly in the Polished Bore Receptacle installed between screens of oil and gas zones.
After landing the completion, the tubing, safety valve, annulus and production packer and tubing hanger were pressure tested to ensure the well was secured prior to removal of the BOPs. After removal of BOPs, the permanent downhole cable and hydraulic control line were fed through the port in the well head and terminated using the appropriate wellhead outlets. The Christmas tree was finally installed and the well starts production. The two wells initially produced a total liquid of a couple of thousand barrels of oil per day with minimal water cut and a high level of production is maintained.
The first well is flowing naturally without any artificial lift, while drilling through the target oil zones, the LWD tool unexpectedly detected good quality thick oil bearing zone at deeper depths.
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Firstly the deeper zone was produced and later the shallow zone after depletion of the deeper zone with high reservoir pressure and high GOR at initial stage. The well has been producing high volume of oil with minimal water cut without AGL.
Here AGL is utilized once the deeper zone is depleted. The AGL can also be used for the deeper reservoir production when decreasing reservoir pressure and increasing water cut require artificial lift at later stage of well. The second well has also been producing a good volume of oil, but with conventional surface gas lift rather than the auto gas lift because, it was found that the gas cap in the upper part of the oil reservoir was not injecting gas through AGL valve from annuals to tubing.
PDGs attached to the AGL valve indicate that the pressure differential between the annuls and tubing was minimal whether the well is flowing or shut in shown in figure. This measurement indicates that gas zone above the swell packer and oil zone below are in full communication without any sign of isolation with swell packer and annuals is full of liquid, instead of gas from the gas cap.
Above psi high pressure difference in annuls is maintained between oil gradient and gas gradient if the annuls is filled with gas from the gas cap shown in fig. The gas cap which was detected with LWD is now flushed with liquid and thus, not able to produce gas. This might have been caused because of formation damage deep into near wellbore matrix due to high overbalance from significantly increased mud weight that was required to control gas kick encountered during drilling. Plan is to continue ongoing good level of production with surface gas lift and then to conduct sandface cleanup at the gas interval when production decreases significantly.
Fig: 29 data from real time monitoring of dual gauge during conducted well test process Fig: 30 Plot of Pr. Such an installation will have several gas lift unloading valves charged with Nitrogen the domes and bellows. The existence of the bellows and nitrogen charge may cause the failure due to, the leakage of nitrogen charge from the dome or bellows damage, resulting valve unusable. Unloading valves may cause multi-pointing resulting system inefficiency. A possibility of mall function of subsea completions and the subsequent cost of intervention is enough to motivate one to minimize the number of unloading valves.
In SPGL system a single orifice valve is installed at a desired depth for well kickoff and continuous gas lift operation. It requires a higher compression. The information is drawn from the current PDF stage. In the initial years the well flow on self, but requires artificial lift in mid-stage. Gas lift is best suited for the field having high GOR and relatively high reliability compared to other modes of lift.
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I deepwater environment the subsea gas lift, flowline and riser system is expected to operate over a wide range of conditions in terms of fluid composition, pressure, temperature, and flow rates. In this case we carry out to evaluate single point gas lift system for the field. Field data: The deepwater filed is located at a distance of 45kms from shore in water depth of — m. The development strategies include clustered subsea wells with the well fluid being produced to a FPSO to be stationed about 12kms away. Wells are placed to be vertical at this stage FDP with total depth range of m. The crude oil is waxy with high pour point of 36 0 which makes flow assurance challenging.
The Field parameters used for simulation Table: and crude oil characteristics Table: are tabulated below. Requirement of Artificial lift: The filed is in partial depletion drive requiring gas lift assistance for 3 wells- B, C, G from mid to late life of the wells. Flowing tubing head Pressure and Temperature profiles over the filed without any artificial lift are obtained from the data shown in figure. But, lift assistance may require to bring back the well on production after a well is shutdown. Once the liquid that has settled in the well have been lifted, the well will start producing naturally without any lift.
And other cases is when there is high GOR or water cut, lift may require to maintain production. General artificial lift methods can give negative results such as inefficient production, pressure loss. In wells with long perforation intervals cause insufficient velocities below the packer can cause liquid loading.
Artificial lift methods are limited in their ability in controlling liquid loading in these types of wells. New innovations in gas lift system create adequate velocity below the packer to recover liquids and maintain the lowest flowing bottom-hole pressure and most efficient operation. As more wells are being drilled and completed with long perforated intervals, liquid loading and pressure build-up often occurs as the result of inadequate velocities below the packer, decreases effectiveness of gas lift.
In order to maintain maximum reservoir drawdown in long perforated intervals operators need alternative methods to control cost. Several innovative methods have been developed that allows gas lift to be effective in deep and long wells.
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These advancements allow gas to be injected to a deeper point in the well to maintain adequate velocities and ensure optimum production rates without applying any back pressure on the formation. Gas is now injected below the packer and deep into the perforated zone by passing the lift gas through and around the packer. The injected gas aerates the liquid in the perforation zone, decreasing the flowing gradient and improving inflow from the formation and by increasing velocity in production string also increase liquid recovery and reduces liquid loading.
Advances in gas lift system design provide several options for optimum recovery of fluid from well bore below packer. Every system has a unique technique that allows gas injection deep into the perforated zone by passing gas below the packer. Annular Bypass Assembly ABA : It is a hybrid of the conventional gas lift system with a packer and open ended packer less system.
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