Hydraulic fracturing has generally been limited to relatively low-permeability reservoirs. In recent years, the use of hydraulic fracturing has expanded significantly to high permeability reservoirs. The objectives of fracturing low permeability reservoirs and high permeability reservoirs are different and defined by reservoir parameters.
The estimation of reservoir permeability, a variable of great importance in hydraulic fracturing design is frequently unknown because candidate wells either do not flow or a pretreatment pressure transient test is required. Consequently, Nolte has introduced a new method for adding after-closure fracturing analysis to the pretreatment calibration testing sequence that defines fracture geometry and fluid loss characteristics. The exhibition of the radial flow is ensured by conducting a specialized calibration test called mini-fall test. The derivations by Nolte, based on the theory of impulse test and principle of superposition, allow the identification of radial flow and thus the determination of reservoir transmissibility and reservoir pressure.
This study presents a review of the after-closure radial flow analysis. A modified method is proposed to complete the Nolte's method for the determination of the reservoir transmissibility and reservoir pressure based on the pressure derivative.
The application of the modified method is demonstrated on actual field data from calibration tests performed on several oil and gas wells. The reservoir parameters determined with this method are verified by comparison with results obtained from buildup tests.
Hydraulic fracturing has been recognized to be an effective means for enhancing well productivity and recoverable reserves, especially for low permeability reservoirs, by reducing the resistance to flow area between the wellbore and formation.
The appropriate fracturing treatment for a given well has been hard to design because of the numerous variables involved. The use of inaccurate reservoir variables to design treatments may lead to poor production estimates.
In wells that are to be hydraulically fractured, minifracture treatment, called also calibration test, frequently is performed to determine parameters needed for the stimulation design. It is generally performed without proppant and therefore, retains negligible conductivity when it closes.
Fracture pressure analysis was pioneered by Nolte1,2. The basic principles are analogous to those for pressure analysis of transient fluid in the reservoir. Both provide a means to interpret complex phenomena occurring underground by analyzing the pressure response resulting from fluid movement in rock formation.
The analysis of fracturing pressure, during injection, during closing and after closure period, provide powerful tools for understanding and improving the fracture process.
Advances in minifracture analysis techniques have provided methods for determination of fracturing treatment design parameters such as leak-off, fracture dimensions, fluid efficiency, closure pressure and reservoir parameters. These parameters can then be used to determine the pad volume required, best fluid loss additives to be used, and most importantly, to achieve the optimum fracturing treatment design.
Fig. 1 shows a typical history of the calibration test from the beginning of pumping until the reservoir disturbance from the fracture decays back to the initial reservoir pressure.
Fracturing pressures during each stage of fracture evolution (i.e. growth, closing and after-closure) provide complementary information pertinent to the fracture design process. Therefore, Fracturing pressure analysis may be reduced to three distinct types of analysis.
Traditionally, operators have had limited options for conducting remedial work on lateral re-entries through milled-casing windows. This limitation is due to the necessity of using a "bent joint" of pipe to guide tools through the window. If a bent joint of pipe cannot be attached to the end of the assembly (e.g. a drilling assembly), a whipstock is required to deflect the assembly out the window. Setting a conventional whipstock requires the use of orienting tools that add significantly to the wellcost.
This paper describes the world's first applications of unique technology that helps solve these problems by facilitating the exiting of milled-casing windows with service tool assemblies during remedial operations. The system uses the patent-pending "self-locating" lateral re-entry technology as an integral component of the Lateral Re-entry Whipstock to assure the proper orientation and elevation of the whipstock tool face with the casing exit window.
The technology described in this paper has bearing on TAML Level II1 junction re-entry operations for clean out, production enhancement, increased reservoir drainage, zonal isolation, and re-completion of lateral wellbores in multilateral completions.
One frequently encountered difficulty in material balance calculation is lack of shut-in reservoir pressure. This work presents a new method that can be applied under pseudo steady-state conditions to simultaneously determine the average reservoir pressure and initial fluid in place using only surface production data and flowing bottom hole pressure. This new method is derived from a combination of a generalized material balance formulation and pseudo steady state theory and is applicable to both oil and gas reservoirs for single-phase flow with no water influx. This method does not rely on pressure build-up tests, knowledge of drainage area or permeability, but it requires flowing bottom hole pressure. For constant flowing bottom-hole pressure or variable production rate, this work presents an algorithm to convert fluctuating or constant flowing bottom hole pressure into corrected flowing bottom-hole pressure with a decline rate essentially identical to that of average reservoir pressure. Methods for analyzing transient flow are also discussed in this work. This new method is useful in analyzing surface production data and flowing bottom hole pressures for reservoirs significantly lacking data.
A frequently encountered difficulty in material balance calculation is lack of measured reservoir pressures, which are usually obtained from shut-in build-up tests. Without shut-in reservoir pressure, it is very difficult to perform material balance calculation. However, production data seems to be available most of the time. If we can make use of sand-face production rate and flowing bottom hole pressure, then it is possible to develop a new method which can be used to determine average reservoir pressure and initial fluid in place (IFIP) simultaneously.
This new method is derived from a combination of generalized material balance method and pseudo-steady state theory to determine reservoir pressure and initial fluid-in-place simultaneously without relying on pressure build-up tests. Furthermore, this new method does not require shutting-in of production, nor does it require a prior knowledge of permeability, drainage area, and shape factor under pseudo-steady state condition.
The objectives of this study are (1) to present detailed mathematical derivation of a new method, which can be used to simultaneously determine average reservoir pressure and IFIP for oil and gas reservoirs without relying on pressure build-up tests and (2) to provide solution algorithms of this new method.
The material balance of hydrocarbon fluid at reservoir condition states that the initial hydrocarbon pore volume is equal to the current hydrocarbon pore volume plus the hydrocarbon pore volume reduction due to (1) pore volume reduction, (2) expansion of initial water saturation, (3) water influx, (4) water injection, and (5) water production. This concept is expressed in equation (1). Detailed derivation of equation (1) can be found in references (1, 2, 3, and 4). Definition of each symbol is given in nomenclature.
This paper presents a new production method in which the reservoir energy spent to lift the production from perforation-depth to the dynamic liquid level is replaced by surface energy, and consequently the well daily rate and cumulative production is increased by 200 - 250 %. The method can be used in any well at any time.
The paper is based on the analysis of how the reservoir energy generated by the expansion of the reservoir fluids is used to produce the well:
PROFITABLE USAGE: Moves the production through the pay zone into the well bore
WASTEFUL USAGE: Sends the reservoir energy to:
Overcome the liquid friction along the production flow path.
Lift the production from perforation-depth to the dynamic liquid level.
Present production practice recognizes and reduces only the reservoir energy wasted to overcome the liquid friction through the pay zone by using better and cleaner perforations, acidizing, fracturing, and other techniques. When less reservoir energy is used to overcome the frictions through the pay zone, the well performance, in both rate and cumulative production, is increased.
To date all artificial lifting methods are spending surface energy only to lift the production from the dynamic liquid level to the surface. However, the energy needed to lift the production from perforation-depth to the dynamic liquid level, the largest waste of reservoir energy, is now overlooked and has not been recognized as the most important way to significantly increase well performance. The proposed new production method substitutes the reservoir energy by surface energy in order to lift the production from perforation-depth to the dynamic liquid level. Accordingly the well performance in day rate and cumulative production is increased by 200 - 250 % compared to the actual well performance.
The quickest and easiest way to produce the well according to the new production method, is to run a subsurface compensated plunger pump assembled from the API Spec-11AX parts, and work with the same beam pump. A subsurface compensated pump, is a liquid lifting device, which can not be drawn by the well pressure.
Water injectivity decline is a very common phenomenon in waterflooding fields. Most of the previous analyses were focusing on water injectivity decline due to the migration of suspended particles in injection water or the injection water/reservoir fluid incompatibility. However, in some unconsolidated formations, another possible mechanism for water injectivity decline is sand mobilization, which means sand particulates separate from rock matrix and move into deep formation. This kind of injectivity decline is controlled by the operation condition of water injection such as injection pressure and injection rate. In this paper, a mathematical model is proposed to simulate the process of sand mobilization and the resultant water injectivity decline.
The mathematical model is derived based on material balance for water, sand particulate, and rock matrix. Also included in this model are particulate generation and deposition constitutive laws, and permeability-porosity correlation. Finite difference scheme is introduced to discretize the partial differential equations and the finite difference equations are solved implicitly through iteration. Sensitivity analysis is performed to study the effects of various factors on water injectivity decline and strategies for managing efficient water injection are proposed through the analysis.
Numerous researches[1-13] have been done in oil/gas well sand production. Because water injectors are not generally back produced and as a result very few researches were done in the past on injector sanding. Literature survey indicates that only a couple of papers[14-15] were published regarding this topic. Despite that, it does not mean sanding in water injectors is not a problem, instead, it can cause the injectivity decreases dramatically. As stated in reference, the injectivity of a well operated by Statoil in the Norwegian Sea decreased from 8000 m3/d to 0 m3/d in just half an hour which is tied to formation failure caused by the pressure waves generated during the sudden shut down of the pumps. From this single example, we can see that how bad it can be in water injectors once sanding occurs. Because of this, researches on sanding in water injectors are of the same importance as those in producers.
Santarelli et al presented a field case study on a reservoir operated by Statoil in the Norweigian Sea concerning the injectivity decline of water injectors. In this paper, it is believed that sanding is caused by the following reasons: 1) During well shut-in, the rock around the well is too weak to sustain the stresses and fails. 2) Because of the reservoir permeability heterogeneity, the wells are cross-flowing during shut-in and cause sand production in front of the perforated intervals. 3) The produced sand is not able settle down in the rat-hole before injection restarts and hence plugs the perforation tunnel. 4) As a result of the water hammer effect caused by well shut-in, the formation already weakened by sand production undergoes liquefaction that triggers large amounts of sand to be released in the well and hence killed the injectivity. Morita et al provided guidelines for completing water injection wells.
Many oilfield service companies as well as oil producers have manually tracked assets over the years for a variety of reasons. The service companies have tracked assets such as pumps, packers, or other products to assist in R&D efforts. Being able to collect the data and compile statistics on run times and component failures enables the service companies to evolve and improve current products as well as design new products. From a producers perspective, compiling the same or similar data allows for the development of "best practices" in operating procedures and processes. Software products developed to address these needs have evolved with time to provide more functionality. However, many systems implemented to handle the total process of data acquisition, warehousing, querying, and reporting to achieve improved operating results have become more difficult and expensive to support than the value added.
The value of the information has not diminished, but increased due to the fluctuations in oil prices and the continuing efforts to reduce lifting costs through design and process enhancements. The recent development of a web based tracking system incorporates workover management, downhole equipment, and chemical usage while enabling the operator and service provider the ability to easily enter and access the data. The system reduces the problems of database synchronization, multiple entries of the same data, and provides a common means through the Internet to interface with the information. The system links the operator in the field, the service company providing equipment or chemicals, and the district office together through a common database that each has access to.
The system allows a technician in a pump shop, workover foreman in the field, or chemical sales person to easily enter data into the system using a laptop computer or touch screen technology. The data is brought back to the service provider's local office and is accessible to the operator through the Internet. Wells, well equipment, and equipment components can be tracked for run life and root cause of failure. The operation becomes an information network that uses the same data to accomplish different tasks but with a common objective of reduced costs and improved profitability.
Ras Budran filed is a massive Nubian sandstone reservoir compartmentalized by major faults acting as partial barriers. Vertical communication is impeded by hydraulically sealing shale layers in the development of three main pressure regimes. A combined water injection and aquifer support the pressure. Pre-mature water breakthrough has been occurred in the middle of oil leg, which in turn limit the corrective action of the isolation of the watered out zones.
3D- geological and reservoir simulation model was constructed, based upon new reservoir characterization with the objective of improving the vertical definitions within the reservoir. The reservoir properties generated by deterministic interpretation for the new micro-zones.
This paper presents the approach taken to match 17 years of production data in particular, via aquifer definition and fault communication.
The history-matched model was then used to confidently check the production and injection well pattern and performance. The matched model then used to investigate the viability of infill wells to improve drainage pattern and sweep efficiency meanwhile increasing ultimate recovery.
Ras Budran field (R/B) is located at the eastern coast of the Gulf of Suez area (Fig 1). The field was discovered in April 1978 and production started in Feb., 1983. Production is maintained by gas lifting while the pressure is supported by a combined water flooding and limited aquifer drive.
There are 17 producing wells and 4 injectors over 3 offshore platforms. The field is relatively deep reservoir with the original oil water contact at 12350 ft-tvdss. Heavily under saturated reservoir with initial reservoir pressure of 5632 psia and the bubble point pressure 1200 psia. The structure contour map Fig. (2) shows the reservoir complexity.
The reservoir is massive sandstone and the macro layers were defined from top to bottom as follows; Raha, Nubian III, IIB, IIA and Unit I. Unit IIA has a shale/sand streaks that work as a vertical hydraulic barrier between the upper and lower units. Lower Units of block, which called Unit I (LA), Upper units of block A (UA), Upper Units of block B (UB) and Upper Units of block C (UC).
Fluid flow in the reservoir is directed from unit I to the juxtaposed upper reservoir units supported by water injection in unit I from injector A3b and direct aquifer support. Fluid flow in upper units of block A is only supported by the water injection through injectors A2, A1 and A9 respectively. Fig (3) illustrates the main cross section for the field.
Due to the nature of Ras Budran reservoir and its dipping structure, peripheral injection pattern was proposed and implemented in the original field development plans in October 1985 through two wells A2a (Unit IIB+III+R), and A3b (Unit I). In January 1990, the system was upgraded with another injector A1 (Units IIB+III), to replace the poor injector A2a and finally, the last injector A9a (Units IIB+III+R) was brought on line in April 1992.
The difference between formation and injection seawater salinity was used as a tool to monitor the flood front and the interblock communication. The field has already produced 80% from the estimated reserves.
Because it will not be possible to capture the dynamics of a water flood project, in particular with high mobility ratios as in the case of Ras Budran, with single cell calculations. Reservoir simulation modeling is essential in order to optimize injection/production well patterns and to optimize sweep efficiency via the injection distribution.
To date, field wide CO2 flooding is continuous or WAG injection processes. In individual wells a huff'n'puff scheme has been used where CO2 is injected into a well followed by a shut-in period; after a predetermined time, the well is produced. Each of these methods have practical, technical, and economical limitations. This paper describes a new CO2 injection method that combines all three of these methods but excludes water injection.
Continuous CO2 may be optimal in reservoirs that are not conducive to water injection and do not have CO2 mobility control problems such as early breakthrough. However, continuous CO2 requires a large initial CO2 volume that may be unavailable and relatively expensive. WAG is very common with variations of different ratios of water to CO2 volumes and tapered ratios. WAG reduces mobility problems and thereby improves areal sweep efficiency; CO2 purchase expenses may be lower due to the requirement of lower CO2 volumes. Unfortunately, water injectivity following CO2 injection may decrease, and the water increases lift and water handling expenses. Huff'n'puff is effective similar to a near wellbore stimulation, but may not realize the benefits of a full field injection program. Also, this adds the complication of injection and production capabilities required in the same well. This may be impossible for some wells on artificial lift.
The proposed method is to inject CO2 and shut in the well similar to the huff and puff, but instead of producing the well inject CO2 again. This process is a cyclic process like WAG, and shares the variables of the duration and volume of CO2 injection and the duration of the shut-in period. This method eliminates injectivity and production expenses associated with water. Mobility is controlled by near wellbore achievement of miscibility by the increase in mass transfer between the CO2 and oil during the shut-in portion of the cycle; i.e. a smaller portion of the reservoir has relatively low viscosity, injected CO2 due to miscibility between oil and gas occurring nearer the injection well.
The use of CO2 as a method of enhanced oil recovery has been studied since the early 1950's1 and its use grew signficantly in the 1970s and 1980s.2 It is used as an enhanced oil recovery (EOR) process where it is injected following either natural drive or waterflooding in order to recover additional oil.
During the life of an oil reservoir, production is usually carried out by primary recovery, secondary recovery, then enhanced oil recovery (EOR). Primary recovery uses the natural energy present in the reservoir to displace oil to the wellbore and includes solution-gas drive, gas-cap drive, natural water drive, fluid expansion, rock expansion, and gravity drainage. Secondary recovery processes add energy to the reservoir by injecting water or immiscible gas and displacing oil to an adjacent producing wellbore. However, because immiscible gases have more mobility problems than water, the secondary recovery stage is almost always carried out with a waterflood. EOR processes are carried out by gas injection, liquid chemical injection and/or the addition of thermal energy. Gas injections are considered EOR processes if the significant recovery mechanisms are not exclusively those of immiscible frontal displacement with high interfacial tension (IFT) relative permeabilities, but include such mechanisms as oil swelling, oil viscosity reduction or favorable phase behavior. The gases used in EOR processes include hydrocarbon gases, CO2, nitrogen, and flue gas. Liquid chemicals include polymers, surfactants, and hydrocarbon solvents. Thermal methods include steam drive, cyclic steam flooding, hot water flooding, and in situ combustion.3
The South Swan Hills Unit, located in north-western Alberta, is a carbonate reef with an original-oil-in-place (OOIP) of approximately 850 MM bbl. Waterflooding was begun in the field during the 1960s, and a staged hydrocarbon miscible flood was begun during the 1970s. Chase gas injection was terminated in the mid-1990s. In 1994, however, miscible flooding was reinitiated in the reef margin area of the field using horizontal injectors and reduced well spacing. The reef margin is an area of thick, stacked pay that experienced high gravity override during the original miscible flood. Four patterns have been developed to date. The two earliest patterns have now completed solvent injection and are on chase waterflood. They have both recovered between 800 M bbl and 900 M bbl of incremental oil per pattern (more than 10% of pattern OOIP) from areas which were part of the original miscible flood.
This paper will detail the past history of the pool under miscible flood, the redevelopment of the reef margin area using horizontal miscible injectors, and the performance of the four patterns implemented to date. The factors that have made this redevelopment successful, and their impact on field production, will also be discussed. Finally, plans for future development of this mature field will also be discussed.
Hydrocarbon miscible flooding has long been a preferred means of enhanced oil recovery (EOR) in Alberta. It is similar to CO2 flooding, with the exception that the solvent is composed of a mixture of hydrocarbon components (usually C1 to C5). The solvent is usually displaced with cheaper chase gas, composed primarily of methane.
An abundance of natural gas liquids (NGLs) in the 1960s and 1970s and the opportunity to incorporate a more efficient displacement process prompted the operator of the South Swan Hills unit (SSHU) to consider a hydrocarbon miscible flood as a means to increase oil recovery.1 An injection pilot of pure NGLs was carried out from 1970 to 1972, and the field scale project started in 1973. Initial design called for 21 patterns to be put on injection in the central and northern portion of the unit. This area was still in early stages of waterflooding, and was termed a secondary miscible flood. The western part of the unit was put on miscible injection in 1982. This area had a relatively mature waterflood, and was thus termed a tertiary miscible flood. Both areas were developed exclusively using vertical wells. Early performance, and an evaluation of the performance of the tertiary miscible flood were documented by Griffith and Cyca.2
A common problem with miscible flooding is gravity override of the solvent due to its much lighter density at reservoir conditions than the in-situ oil and water. This was identified as a concern during the design of the original miscible flood, and was observed in the field. One area particularly prone to override was the reef margin, with its thick, continuous, stacked pay.
One means of increasing recovery in miscible flood projects is to use horizontal injectors. Taber and Sereight noted several benefits that might be realized through the use of horizontal injectors including improved sweep, improved displacement efficiency, faster reservoir processing, and the minimum miscibility pressure maintained over a larger portion of the reservoir.3
The concept of horizontal injectors applied to SSHU (and some of the other geologically similar reservoirs in the area) is illustrated in Figure 1. The horizontal well is placed low in the pay section to sweep reservoir that was missed due to gravity override during injection into vertical wells. Chugh et al describe a model study and consequent field implementation of such a miscible injector in the Virginia Hills field (a sister reservoir to SSHU) in 1997.4
Much recent attention has been recently given to depletion of U.S. natural gas reserves, particularly since many forecasts predict a 30 TCF annual gas market. A comprehensive look at the way initial production, decline rates, and reserves have changed over the last 30 years in Texas, the source of 1/3 of the country's natural gas, leads to concern about whether current drilling activity will be able to maintain the current supply, much less increase gas production1.
The decline rates in new Texas gas wells have changed from about 20% in the first year for wells drilled in the 1970's and 1980's, to more than 55% for wells drilled in 1998 and 1999. At the same time, the contribution to the state's supply from new wells has sharply increased from 8% of the state's supply to more than 15%. Although the initial production rates from an average well have actually improved from a low of 15 MMCF per month in the early 1980's, to 44 MMCF per month in 1999 due to improved completion technology and horizontal drilling, the combined effects of fewer completions and high decline rates suggests that a decrease in Texas' production capacity may occur in the near future. Drilling above the current activity will be necessary to sustain the state's gas production.
Normalized rate vs. time curves were developed for each year since 1970 to obtain initial rates and decline profiles. The curves were extrapolated to an estimated ultimate recovery, changing from 6 BCF per well in the early 1970's to 1 BCF per well in the late 1990's.
Texas has been the source of 39% of the approximately 882 TCF marketed in the U.S. since 1945. The state currently supplies about 32% of the country's natural gas and holds 27% of the proved reserves2. By any measure its contribution to the U.S. supply is significant.
Natural gas reserve-to-production ratios have been fairly constant in recent years for both the U.S. and Texas, and stand at 8.7 years and 7.4 years, respectively, for the year ending in 1999.