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Abstract This paper presents an investigation of the validity of applying the constant-pressure liquid solution to transient rate-decline analysis of gas wells. Pseudo-pressure, non-Darcy flow effects, and formation damage are incorporated in the liquid solution to simulate actual real gas flow in the vicinity of the wellbore. The study shows that for constant-bottomhole pressure gas production the conventional semilog plot of the inverse of the dimensionless rate versus the dimensionless time used for liquid solution has to be modified to consider the high-velocity flow effects. This is especially true when the reservoir permeability is higher than 1 md and the well test is affected by non-Darcy flow and formation damage. This paper also presents a novel systematic method to determine the formation permeability, mechanical skin factor, and non-Darcy flow coefficient from a single constant-pressure production test. The working equations are written in such a way that allows a graphical analysis of the variable rate with time that is analogous to the analysis of constant-rate production test. The analysis procedure is simple and straightforward. It does not require type-curve matching or correlations. The applicability of the proposed method is illustrated using several simulated examples. The input formation permeability varies from a low value of 0.1 md to a high value of 5 md. The ratio of the downhole pressure to the initial reservoir pressure ranges from 0.1 to 0.8. Introduction The majority of gas well tests are performed assuming constant-rate production conditions. A close inspection of field practices shows that in many cases constant-bottomhole pressure production is desirable and yields results that are as accurate as those obtained from constant-rate production. Geothermal wells, fluid flow into a constant-pressure separator or pipeline, open wells flowing at atmospheric pressure, declining-rate production during reservoir depletion, and production from low-permeability gas reservoirs are few examples where oil and gas wells can be operated under constant-bottomhole pressure conditions. Most gas reserves around the world are found in tight reservoirs where the formation permeability varies from 0.01 md to 5 md. These types of gas reservoirs provide excellent opportunity for constant-pressure production practices. As early as 1949, van Everdingen and Hurst presented analytical constant-pressure radial flow solutions for the diffusivity equation. Jacob and Lohman suggested analytical solution in terms of dimensionless flow rate for wells operating under constant-downhole pressure conditions. Tabulated values of dimensionless flow rate versus dimensionless time were provided by Tsarevich and Kuranov for bounded circular systems and by Ferris et al. for unbounded reservoirs. Different methods for the analysis of liquid well test data with constant-pressure conditions at the wellbore were proposed by van Poollen. As far as we know, the first attempt to use conventional semilog techniques to analyze pressure buildup test for a well produced at constant wellbore pressure was suggested by Clegg who used Laplace transforms to obtain approximate solution at large dimensionless production time. More recently, Samaniego and Cinco-Ley investigated the influence of pressure-dependent fluid and rock properties on well production decline in constant-wellbore pressure tests. Uraiet and Raghavan studied the transient pressure behavior in the drainage area of oil wells at constant wellbore pressure. They illustrated the validity of the "infinitesimally-thin" skin and effective wellbore radius concepts to describe the skin region in the vicinity of a well producing at constant-bottomhole pressure. In a different study, Uraiet and Raghavan followed the constant-rate production approach to present a simple procedure to analyze pressure buildup data of a well producing a slightly compressible liquid at constant-pressure conditions. Ehlig-Economides and Ramey suggested various techniques for the analysis of constant-pressure drawdown test of oil wells that are analogous to the conventional constant-rate test. In a separate study, Ehlig-Economides and Ramey used the principle of superposition of continuously varying flow rates to generate an exact solution for buildup test following constant-pressure flow conditions. Camacho-V presented procedures to determine reservoir parameters from constant-pressure drawdown tests conducted on solution-gas-drive reservoirs.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract PDO currently operates more than 4000 wells in over 100 fields. The fields are diverse in terms of their reservoir, drive and development strategies. Despite this diversity, there are strong common drivers for smart wells/fields. Many fields are artificially lifted (beam pumps in S. Oman, gas lift in N. and central Oman, increasingly ESPs in all areas) with SCADA systems already in place. There is a progressive drive towards centralised, automated production facilities for reasons of safety. Reservoir depths and low drilling costs support relatively dense economic well spacing where it is technically feasible to connect large amounts of reservoir to a single wellbore; this saves development CAPEX but makes maintaining effective control of the reservoir more difficult. Smart wells is an umbrella term referring to the systemic integration of emerging down-hole measurement, communication, control and processing technologies in well and asset design. As an integrated technology bundle, they have the potential fundamentally to change the E&P industry. A range of smart technology trials have been conducted and/or are planned, including down-hole monitoring, measurement, controlling and artificial lift optimisation. PDO is applying many smart well technologies to monitor, measure, control and optimise production from multi lateral wells. This paper focuses on following applied technologies;Distributed Temperature Sensing (DTS) to monitor water and steam flooding wells. Down-Hole 2-Phase Metering in ESP and BP wells to measure water cut of dual lateral wells. Digital Hydraulic Control Valves to control production of a multilateral well. The paper is intended to cover the above applied smart well technology trials, share the experience with respect to their outcomes (success and failures) during the execution. It also provides an assessment of the values of these technologies to PDO. Introduction PDO currently operates more than 4000 wells in more than 100 fields spread over a very large geographical area. Most of these fields are matured and have reached their seconday development phase. Therefore it becomes very important and critical to have a reservoir and production monitoring and management in order to optimize production of the wells. Most of these wells are also artificially lifted which needs continuous monitoring to keep them running smoothly to increase uptime of the wells. Hence, PDO has embarked on a program to implement smart well technologies across most of the fields. The main objectives of these technologies were to enhance production and improve reservoir management by having better control, monitoring and optimization of the wells. Smart Well Technology Strategy and Implementation A Smart Well technology strategy for PDO has been set in 2000 in which value adding opportunities have been identified. It is realized that the technology targets that can be resolved with the application of Smart Well technology are:Water/steamflood front monitoring to accelerate recovery and reduce lost UR by successful fracture shut-off and improved sweep efficiency. Multiphase metering of multilateral and extended horizontal wells to monitor water inflow and plan intervention activities. Selective zonal and multilateral leg control to reduce well intervention costs and improve reservoir management so increasing UR and accelerating recovery Self optimising artificial lift to increase UR by accelerating oil production and to increase run life thus reducing deferment and reduce OPEX. Fracture orientation determination to make informed decisions on future in-fill wells and save DRILLEX, increase UR and accelerate recovery through optimised drainage and injection patterns
- Asia > Middle East > Oman > Al Wusta Governorate > Ghaba Salt Basin > Qarn Alam Field (0.99)
- Asia > Middle East > Oman > Thamama Group > Shu'aiba Formation (0.98)
Abstract Sand control has been a challenge to the petroleum industry since oil and gas was produced from weakly cemented sandstone formations. Several techniques have been applied;restricted (critical) production rate, screen and/or gravel packing, sand consolidation, FracPacking, oriented and/or selective perforation, and combination of any of the above. Sand formations may fail in compression, tension, and cohesion that trigger sand production. The compressive failure occurs during drilling where the rock cannot withstand the new stress field and/or the cementation materials have deteriorated from mud filtrate exposure. The calculation of mud weight to prevent compressive failure will be presented in this paper. Additionally the failed zone is usually oriented in the direction of minimum horizontal stress which can be avoided during perforation by orienting the perforation tunnels in the direction of maximum horizontal stress. During completion the cementation materials should be protected from completion fluids. During production a pressure drawdown is established for a given production rate. This pressure drawdown may cause rock failure in tension or cohesion (erosion) leading to sand production. The near-wellbore pressure is caused by skin damage due to reduced permeability, stressed region, convergence flow, and partial penetration. This paper presents a model to determine the critical pressure drawdown based on relating the near-wellbore pressure drawdown to the tensile and cohesive strengths of the formation. Hydraulic fracturing, referred to as FracPack, may be applied to alleviate the near-wellbore pressure drawdown below the critical value that causes sand failure. Two fracture parameters are designed to achieve this goal; fracture length and fracture conductivity. This paper presents a design criterion to determine these parameters to optimize a FracPack design for sand control. Examples from a field in Saudi Arabia will be used to validate the application of controlling sand production using screenless FracPack completion. In these wells a FracPack treatment alone controls sand production. The multirate test used in these wells and the FracPack design for fracturing treatments will be presented. Introduction Sand production has historically been a problem associated with soft or poorly consolidated formations. The result is usually lost production due to formation sand and fines plugging gravel packs, screens, perforations, tubular, and surface flow lines or separators. In addition to damaging pumps or other downhole equipment, erosion of casing and surface facilities may also occur. Sanding problems may actually cause loss or recompletion of a well due to casing and/or hole collapse. The methods applied to minimize the effect of sand production include critical production rate, gravel packing, sand consolidation, FracPacking, oriented and/or selective Perforation, expandable sand screen, or a combination of these methods. Completion methods are selected based on sand characterization and failure mechanism. Laboratory testing and mathematical models used for sand prediction are selected based on sand characterization. FracPac completion has been replacing gravel packing in many petroleum reservoirs. However FracPack with a screen in hole, is also widely applied. This paper will discuss the process of sand control from the time a given formation is exposed to man's disturbance and will sicuss sand control during drilling, completion, and production.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (0.89)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.70)
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Safaniya Field (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- (7 more...)
- Well Completion > Sand Control (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
Abstract High pressure/high temperature (HPHT) wells can present a myriad of challenges including lost circulation, well kicks, underground blowouts, or other mechanical constraints before a final target depth of 12,000 ft or more is reached. Thereafter, the bottomhole environment with temperatures of 300+deg F and pressures exceeding 10,000 psi test the limits of hardware and chemicals. Each operational misjudgment or tool malfunction can impact the well costs significantly. For example, the pipe trip time to correct such problems can run into twelve to twenty four hours of non-productive time. This paper addresses a well control issue in a HPHT exploration well where a possible underground crossflow was in progress and the well was losing oil-based mud. Several days were spent trying to control the well by using various fluids (some conventional and others new) but with no success. Eventually a new, Wellbore Pressure Containment Improvement System (WPCIS) was implemented, and it controlled the losses effectively. The well had been losing at an ECD (equivalent circulating density) of 16.4 ppg. Application of the WPCIS process improved the wellbore pressure containment (WPC) side of the mud weight window to sustain an equivalent of 17.0 ppg mud as measured by a formation integrity test (FIT). This remarkable WPC improvement was achieved along with several other cost saving factors. The discussions in this paper will further reveal the workings and applicability of the WPCIS as a process that can help optimize well plans leading to lower costs for drilling fluids, casing design, cementing, and completion equipment. Introduction Drilling in the offshore Nile Delta of the Mediterranean Sea (Fig. 1) delivers varied experiences and challenges to its explorers. The targets are mainly in the Pliocene and pre- Pliocene sands of the Nile Delta. Exploration successes mainly hinge on understanding the regional pressure trends and the complex structural elements and seismic quality challenges. Target certainty can sometimes be elusive for the deeper horizons (such as the Miocene targets) owing to small target area and severe faulting that can make interception very difficult. Pressure regimes are treacherous where geo-pressured shale bound sands that may exhibit pressure regression. The mud weight margins are critical and can easily lead into loss or gain situations within an ECD margin of 0.03 ppge (pounds per gallon equivalent). The formations also show a tendency to "balloon" during tripping out of hole especially after a zone has been losing minor amounts of mud. The formation starts to packoff around the pipe and makes tripping out impossible. These difficulties can be compounded by the well swabbing in the wellbore fluid. "Pumping out of hole" is the normal method to facilitate tripping of pipe. Extreme caution needs to be taken in this operation to decipher between a benign swab and an actual well kick. There could be several drilling engineering papers written on the drilling in the Med Sea area, however this paper deals with a well control situation that developed in the final hole section leading to the Serravalian sands at a depth of around 15500 ft with a bottom hole temperature of 300 deg F and over 12,000 psi pressure. Case History Background Information The 9 5/8-in. liner was landed at 4274 m MD (4098 m TVD) to isolate the A-60 and A-70 sands of the Pliocene, (please see Fig. 2). Due to possible bypassing in the liner wiper plugs, no cement was found in the shoe track. A Leakoff Test (LOT) of 17.8 ppge was achieved at the 9 5/8-in. liner shoe with 15.7 ppg mud in hole. There was some concern about not having properly isolated the previous 12 1/4-in. hole section, especially since it had witnessed a loss circulation and kick situation with 15.7 ppg mud weight (MW). However, the new 8 1/2-in hole section was found to be static with 15.7 ppg MW. A change in the C3-C4 ratio of the background gas between current depth and the โkickโ zone also confirmed its isolation from the last section.
- North America > United States (0.68)
- Africa > Middle East > Egypt > Nile Delta (0.45)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials (1.00)
Abstract Asphaltene deposits have been observed in a number of high gas-oil ratio (GOR) wells in north Ghawar. Even though the oil reservoir is undersaturated two small gas-caps are present as a result of gas injection during the 1960s and 1970s. New development wells drilled recently to produce oil and gas from the gas-cap areas have experienced asphaltene deposition. The cause of precipitation is the stripping of the asphaltenes from the crude by the gas. This paper describes the results of an investigative study that was initiated to determine the precipitation mechanism and ways to alleviate the deposition problem. Asphaltene precipitation experiments were conducted at reservoir conditions in a special PVT apparatus. The effect of gas-oil ratio on asphaltene precipitation was determined by titrating the reservoir oil with gas-cap gas. Bulk deposition tests were also performed at different GORs with reservoir fluids. The results demonstrate that the onset of asphaltene precipitation occurs at relatively low GOR values. However, the amount of asphaltene precipitated at the onset is negligible. Asphaltene precipitation and deposition increase with increasing GORs. Asphaltene deposition envelopes are provided for the reservoir oil as a function of pressure and temperature. Guidelines are provided to alleviate the problem by controlling the GORs. Recipes for solvent treatment including asphaltene dispersants are also described in the paper. Introduction Ghawar field is one of the major oil fields in Saudi Arabia. In the northern part of the field some wells have experienced solid built-up in the wellbore. Analyses of solid samples from several wells have shown the presence of asphaltenes that may have precipitated during crude production and have started to deposit on the wellbore. The solid deposition has been observed in high gas-oil ratio wells. A location map of the wells is shown in Figure 1 and photographs of the solid deposit from one well are shown in Figure 2. The Arab-D reservoir of Ghawar field contains an undersaturated light oil. The bubble point pressure is ~1,900 psi at the reservoir temperature of 215ยฐF and the average gas oil ratio is ~570 scf/stb. The reservoir pressure at present is over 3000 psi. In the 1960s and 1970s the associated gases from part of the field were injected back into the reservoir at two locations due to unavailability of gas processing facilities and to avoid excessive flaring. The injected gases have formed two separate gas caps in the field (north and south gas-caps, Figure 1). In recent years oil production has started from these gas-cap regions. Due to the presence of the gas cap, some of the free gas flows into the oil production wells increasing their total gas oil ratios (GORs). The coning or cresting of gas into the oil has caused limited plugging in a few wells in the north and south gas-cap areas. The gas strips the oil of asphaltenes which precipitate and deposit in the wellbores. Plugging of the wellbore by asphaltenes or organic deposits has the potential to reduce productivity and cause production impairment. Furthermore, several more gas-cap wells are being planned to be drilled in the area and their productivity may be impacted by the deposition tendency. Figure 3 shows the GOR for 11 wells in which asphaltene deposits have been observed. The solid line shows the average GOR for the entire field (~570 scf/stb). Except for one well, the GOR for all wells is higher (in some cases substantially higher) than the average field GOR. The high GOR is a consequence of gas coning/cresting in the wells. The free gas strips the asphaltenes from the crude which deposit in the wellbore. One well was tagged over a period of time to ascertain the buildup of asphaltenes in the well. Figure 4 shows the tag depths and indicates a loss of wellbore accessibility of ~200 ft over a period of 18 months. Recent results show that the buildup has stabilized and the asphaltenes may be dragged with the oil to the gas oil separating plant (GOSP). Other wells are also being monitored and have shown some buildup activity.
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate (0.44)
- Asia > Middle East > Qatar > Arabian Gulf (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.53)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract The Sajaa gas/condensate field is located onshore in the Emirate of Sharjah UAE. Production is from the Thamama limestone reservoir at 11โ13,000 ft. TVD. Reservoir pressure depletion is creating an ever increasing collapse pressure differential on casing opposite overlying sediments. Sajaa field has a history of collapsed casing on wells Sajaa 33 and 39, with two collapse events in the latter wellbore. The current study summarizes the theoretical effort to prevent collapse in the remaining Sajaa wells. A companion paper discusses the related live well workover program. Current Sajaa completions are packerless, producing up the tubing or up the annulus between the production casing and a capillary string for corrosion inhibition. Coincidentally, the collapse resistance of the production casing is reduced by severe wear associated with the use of tungsten carbide hard banding while drilling the reservoir sections of the wellbore. Setting the context for the study, the well(s) tubular program, pore and internal pressures, and design safety factors are presented. This introductory portion also clarifies the differential collapse load to which the tubulars are subjected. Loss of collapse resistance due to severe wear is then addressed. The theory of wear prediction is reviewed, and then demonstrated, as the drilling parameters of several of the affected wells are used to predict their current state. These predictions are then compared to mechanical caliper measurements taken during intervention and repair. Further, using specially machined wear grooves, the effect of wear on collapse of a casing cross section is experimentally validated by full scale collapse tests. Results of both the wear prediction/measurement and its effect of collapse resistance are input to a probabilistic decision tree to tailor each well's workover strategy. The decision tree permits risk-weighting of alternate strategies for repairing the Sajaa casing. An important component of the decision tree is the consideration for time varying alteration of the collapse differential pressure with reservoir depletion. Introduction The Sajaa gas/condensate field is located in the Emirate of Sharjah, UAE. The Thamama reservoir is at depth 11,000 ft., at temperature 300ยฐF, and possessed an initial reservoir pressure of 8000 psi. A typical wellbore design (Fig. 1) targets the Nahr Umr to be top set with 9โ5/8 in. 53.5 lbf/ft L-80 casing. This is accomplished by drilling through the Padbdeh clays, Aruma and Lower Aruma, the Aruma formation requiring 14 ppg fluid densities. The Aruma consists of marls, limestones, claystones and siltstones, and is the pressure bearing formation creating high collapse differentials across the production casing. The top of the 7 in. production liner is typically chosen above the Nahr Umr shale which extends 450 ft. above the top of the Thamama, the base of the 7 in. liner depending on the well (horizontal, sidetrack). The Nahr Umr is a high quality seal.
- Asia > Middle East > UAE > Sharjah > Oman Mountains Foldbelt Basin > Sajaa Field > Thamama Group Formation (0.99)
- Asia > Middle East > Oman > Central Oman > South Oman Salt Basin > Nahr Umr Formation (0.99)
- Asia > Middle East > Saudi Arabia > Thamama Group Formation (0.98)
Abstract Over the past four years, Saudi Aramco has drilled over eighty horizontal wells, onshore and offshore. It has successfully applied this technology to develop new reservoirs as well as enhance recovery from its mature fields. This paper presents the reservoir engineering aspects of 'horizontal' and 'high angle' wells drilled in a major offshore field in Saudi Arabia. It shows how horizontal wells have a) increased the recovery of bypassed oil, b) improved well productivity in tight reservoirs, c) increased production from thin oil zones underlain by water, and d) improved peripheral injection. The paper discusses the actual performance of the horizontal wells and compares them with offset conventional wells. It presents the results of logging and testing of these wells, and highlights actual field data on a) relationship between productivity gain and horizontal length, b) pressure loss along the horizontal wellbore, and c) effect of heterogeneity on coning and inflow performance. Introduction The field is a large anticline that produces high gravity crude (37 -39 API) from Jurassic carbonate formations. There are two major reservoirs both of which are highly heterogeneous, and consist of a mixture of lithofacies with permeabilities ranging from 1 md to over 500 md. The complexity of the reservoirs is illustrated in Fig. 1 by a north-south cross-section through the upper reservoir showing distribution of nine different lithofacies which in turn govern the distribution of permeability in the reservoir. The reservoirs are also highly stratified with large contrasts in permeability between layers, see Fig. 2. Both the upper and lower reservoirs came on production in 1970. P. 381
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.55)
Abstract As producing wells in the Middle East mature, downhole corrosion problems are causing increased blowout risk. Well 159 was drilled in 1959 and was completed within the shallow "Ac" sandstone reservoir with perforations at 2029' to 2062'. External Casing Corrosion and tubing failure lead to an underground blowout. Casings near surface had deteriorated to the point that wellbore access from surface was no longer possible to control the blowout. An estimated 8 MMscfpd gas containing 1000 PPM H2S and 6% CO2 was blowing into a shallow brackish water aquifer (150' to 700'). Well 159 wellhead vibrated at surface from subsurface flow. Gas leaked out of the aquifer into cellars of Well 159 and surrounding wells. This complicated field operations and placed offset wells at increased risk. This paper describes a case history of the relief well used to successfully control the underground blowout of Well 159. Introduction Older producing wells in mature reservoirs can become blowouts. External and internal corrosion of production casing and tubing can lead to a blowout as was the case in Well 159. Thirty six years after this well was completed, a routine annulus survey indicated a tubing leak to the 5" production casing. Several attempts were made to work the well over to get near the producing perforations after pulling part of the original completion. These conventional attempts all failed. Two attempts to kill and cement off flow using a snubbing unit failed. Casing had severely corroded in the interval within the shallow aquifer from 300' to 700'. Casing was parted and shifted below 681' and the wellbore was no longer accessible from surface below this depth. The best guess well configuration prior to drilling the relief well in March 1993 is seen in Figure 1. Gas was flowing up a channeled cement plug within the 5" casing and possibly up the 10 joints of lost 2-3/8" tubing. Blowout flow rate was estimated at 8 MMscfpd of gas. This caused significant safety problems as follows:โsour gas venting out of the charged aquifer in well cellars; โsubsurface charging and associated shallow gas hazard. P. 223
- North America > United States (0.68)
- Asia > Middle East > Bahrain (0.66)
ABSTRACT: Petroleum Development Oman (PDO) has drilled 350 horizontal wells in the past 8 years in 33 different oil and gas fields. Since the first wells were drilled the technology and its applications have evolved considerably. The paper describes that rapid evolution Wing four fields as examples. There has been a diversification of well designs as we have learnt how to tailor horizontal drilling most effectively to different situations. In many cases wells can be drilled faster and cheaper than 5 years ago, but there are also examples where more elaborate designs have been applied. The geological targeting and evaluation of the wells has also improved. Further evolution is planned with the next step likely to be the wider we of multiwell bore horizontals. Introduction PDO produces 730 000 bbl/d (119 000 m3/d) of crude oil from some 70 fields of which 33% comes from horizontal wells. Horizontal drilling was started in 1986 with three short radius wells drilled in chalky oil reservoirs prone to gas or water coning and low production rates. Results were not sufficiently encouraging to lead to further activity in the short term. Horizontal drilling technology evolved rapidly and in 1990 PDO embarked on a more ambitious programme (Ref. 1). The results this time were so impressive that the trial was extended and has led to almost continuous horizontal drilling (80% of all wells drilled in 1994). So far 330 horizontal wells have been drilled of which 300 are operational producers and 20 are injectors (Figs. 1 and 2). Some 100 horizontal wells per year are expected to be drilled for the foreseeable future. These wells exploit both clastic and carbonate reservoirs from Precambrian to Cretaceous age, thin and thick oil columns, light and heavy oil, and a wide range of reservoir quality. Reservoir depth varies from 300 to 3000 m with up to 1900 m of horizontal section. Recovery processes include bottom and edge water drive, solution gas drive, gas-oil gravity drainage and waterflood (Figs. 3 and 4). Horizontal drilling in PDO has shown significant benefits in increased production rates, reduced costs and increased oil recovery from existing producing fields and previously uncommercial oil accumulations. Well costs have been reduced by optimising the well design and drilling operations. The most significant cost saving has been due to a reduction in hole size and casing scheme. These improvements have been made without compromIsing well integrity or inItial production rate. P. 391
- Asia > Middle East > Oman > Al Wusta Governorate (0.29)
- North America > United States > Texas > Dawson County (0.28)
- Geology > Petroleum Play Type (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.89)
- Asia > Middle East > Oman > Thamama Group > Shu'aiba Formation (0.99)
- Asia > Middle East > Oman > South Oman > South Oman Salt Basin > Gharif Formation (0.99)
- Asia > Middle East > Oman > Dhofar Governorate > South Oman Salt Basin > Marmul Field > Al-Qalata Formation (0.99)
- (7 more...)
Abstract Two new innovations - all automatically released gun hanger, and a modular gun-deployment system have recently been introduced to the oilfield to better support perforating needs in wells in which the completion configurations differ from the older, traditionally accepted designs. The first design, all automatically-released gun hanger, was planned originally for monobore completions to allow a zone to be perforated and tested without imposing ally downhole restrictions. This gun hanger can be used below a retrievable or permanent packer, a polished bore receptacle, or an electric submersible pump. A new modular gun system has also been designed to be run in conjunction with the gun hanger. This system allows operators to deploy long gun intervals, a section at a time, into a well. The guns are run into the wellbore individually and stacked on a gun hanger until the appropriate length is achieved. Since this method avoids any gun length restrictions that could be caused by a lubricator, it is ideal for rigless completions. In addition, the capability of the system to allow retrieval of ally or all of the modules under pressure makes it ideal for use in wells with limited rathole. The combined technological advantages of these new completion tools increase production capability of the wellbore by allowing 1) maximum tubular ID usage and 2) perforating capabilities that include maximum gun size, optimum shot patterns and density, and maximum underbalance or overbalance. These enhancements are in keeping with the current operational and economic needs in today's oilfield. Introduction The economic climate in today's oil and gas industry compels operators to review all completion techniques for capability to provide the most efficient, cost-effective methods for maximization of production. During these investigations, technologies have been merged into newer, more efficient systems that could offer enhanced capabilities. Following this trend, several enhanced completion concepts and tubing-conveyed perforating systems have also been combined to provide better operational methods. P. 469
- Well Drilling (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)