Analysis based on analytical solutions dominates in conventional well testing analysis. Analytical solutions, however, meet their challenges under some complex test conditions. This paper presents a case study of horizontal well testing analysis and performance evaluation using simulation approach. In this case study, we show an example that the horizontal well tests could not be analyzed using conventional well testing methods, but they could be analyzed using simulation approach (a single well model in this case). By history matching the well tests, we calibrated the single well model. Then using the calibrated model, we evaluated the horizontal well performance. In evaluating horizontal well performance, we first analyzed the actual well performance and then investigated several factors which could affect a horizontal well performance. We also used the single well model to design a new drawdown test. The new drawdown test was successfully conducted and analyzed using an analytical model. The analysis results are consistent with those obtained from the earlier tests analyzed using simulation approach.
The studied horizontal well, Well A, is the first horizontal well trial in the field of interest. The well performance was poorer than expected. The evaluation of this well performance was crucial to a business decision whether or not to drill more horizontal wells in the field. There was no regular production history for this well. Basically, only two buildup tests (pre-stimulation and post-stimulation tests) and one drawdown test were run. It was found that these test data were not analyzable using conventional well test analytical models. We analyzed the tests using simulation approach. By history matching these tests, we calibrated the reservoir model. Using the calibrated model, we evaluated the horizontal well performance. Based on the lessons we learned from the previous two buildup tests and one drawdown test, we designed another drawdown test. The drawdown test was successfully conducted and analyzed. In this study ECLIPSE simulator and the well testing software PanSystem were used.
Horizontal well technology has been widely used in developing gas fields. Very commonly, these wells are hydraulically fractured to improve productivity in low permeability reservoirs. A previously developed method, the Distributed Volumetric Source method (DVS), was applied to horizontal gas wells with or without fractures to predict well performance. The method is flexible and can be easily applied. The method provides an effective tool to evaluate horizontal well design and well stimulation design for gas wells.
In this paper, we conducted a well performance study by applying the DVS method to typical gas formations in East Texas Basin, San Juan Basin, and Appalachian Basin.. The objective is to determine the best practice to produce from horizontal gas wells. With the transient flow feature of the DVS method, well placement for multiple horizontal wells in a defined drainage area can be studied, and the limit of well spacing and wellbore length is identified. For fractured wells, well performance of a single fracture and multiple fractures are compared, and the effect of the number of fractures on productivity of the well is presented. Realizing that reservoir permeability and anisotropy ratio are the critical parameters in developing low-permeability gas fields, the effect of permeability on well performance, well placement and fracture treatment design is addressed in the paper.
Horizontal and multilateral completions are a proven, superior development option compared to conventional solutions in many reservoir situations. However, they are still susceptible to coning toward the heel of the well despite their maximizing of reservoir contact. This is due to frictional pressure drop and/or permeability variations along the well. Annular flow, leading to severe erosion "hot-spots" and plugging of screens is another challenge. Inflow Control Devices (ICDs) were proposed as a solution to these difficulties in the early ‘90s. ICDs have recently gained popularity and are being increasingly applied to a wider range of field types. Their efficacy to control the well inflow profile has been confirmed by a variety of field monitoring techniques.
An ICD is a choking device installed as part of the sandface completion hardware. It aims to balance the horizontal well's inflow profile and minimize the annular flow at the cost of a limited, extra pressure drop. Fractured and more heterogeneous formations require, in addition, the installation of annular isolation. The new technologies of Swell Packers and Constrictors can provide this annular isolation in an operationally simple manner.
This paper describes the history of ICD development with an emphasis on the designs available and their areas of application. These technical criteria will be illustrated using published field examples. The ICD's flexibility will be shown by its integration with other conventional and advanced production technologies e.g. Stand-Alone-Screens, annular isolation, artificial lift, gravel packs and intelligent completions in both horizontal and multilateral wells.
It will be shown how the value of such well-construction options can be quantified using commercially available, modelling simulators. Simple, but reliable, guidelines on how to model the performance of ICDs over the well's life will be provided. This technique can thus be used as part of the value quantification process for both the evaluation of completion options and for their detailed design.
Horizontal and multilateral wells are becoming a basic well architecture in current field developments. Advances in drilling technology during the past 20 years facilitated the drilling and completion of long (extended reach) horizontal and multilateral wells with the primary objective of maximising the reservoir contact. The increase in reservoir exposure through the extension of well length helped lower the pressure drawdown required to achieve the same rate and enhance the well productivity1-2. Major operators have proved the advantages of such wells in improving recovery and lowering the cost per unit length. The production from thin oil column reservoirs (e.g. The Norwegian Troll Field) became a reality thanks to such wells3-4.
However, the increase in wellbore length and exposure to different reservoir facies came at a cost. Frictional pressure drop caused by fluid flow in horizontal sections resulted in higher drawdown-pressure in the heel section of the completion, causing an unbalanced fluid influx. Hence, coning of water and gas toward the heel of the well was observed. Variable distribution of permeability along the wellbore also results in variation of the fluid influx along the completion and an uneven sweep of the reservoir.
Annular flow is another challenge often encountered when horizontal wellbores are completed with Stand-Alone-Screens (SAS) or with pre-perforated/Slotted liners. Neither of these completion options employs any form of isolation between the casing and the formation (i.e. external casing packers). Annular flow, which is dependent on many parameters such as the size of the clearance between the sandface and the liner (screen) outer diameter, still imposes several problems including: dislodging of the sand grains causing erosion of the sandface, formation of "hot-spots" and plugging of the sand screens5-6. Previously, the elimination of such phenomenon required the utilization of gravel packs or installation of Expandable Sand Screens (ESS), which often had a significant impact on the well productivity and/or involved a very complex operation6-7.
Many of today's aggressive drilling programs require well construction through sour formations to reach remote reservoirs. This has exposed limitations of traditional steel chemistries used for bottom hole assembly (BHA) components. For many years, the industry has used traditional API materials in environments with low concentrations of hydrogen sulfide (H2S) and carbon dioxide (CO2). Higher temperature and low stress conditions in the deeper portion of the well have allowed for these BHA materials to operate adequately with few issues. However, the drive to drill in more corrosive and sour environments has increased the need to develop materials more aptly suited for harsh sour service conditions.
To date, standardization bodies such as API and ISO do not provide specifications for the manufacture of sour service drill stem components. Consequently, organizational bodies such as the Industry Recommended Practices (IRP) in Canada are developing their own requirements for sour applications. The stringent requirements and improved mechanical properties required for sour applications prompted the industry to move away from API materials.
This paper will present test results comparing standard API material and several alloyed variations. Results indicate that alloyed variations show a slight increase in resistance to hydrogen sulfide under low level concentrations while under higher concentrations; the materials show little to zero improvement. This paper will also present emerging alloying technology and enhanced heat treatment processes that have yielded materials exceptionally suited for aggressive sour applications. These materials exhibit excellent resistance to sulfide stress cracking (SSC) and have been successfully used in some of the most severe corrosive environments in the world (also presented). These enhanced BHA materials will significantly improve drilling efficiency by eliminating the risk of failure due to H2S and CO2 exposure.
More aggressive drilling programs have pushed the limits of existing downhole components especially for sour service applications (H2S is present). For many years, the drilling industry has been using traditional material chemistries for BHA components that were developed decades ago. API or ISO does not have specifications regarding sour service applications. Regulating bodies for sour service applications such as The National Association for Corrosion Engineers1 (NACE) focus on casing and tubing components and do not address specifically drill pipe or BHA components.
The industry has responded by developing its own set of recommendations for sour service specifications individually. In order to satisfy the industry's need for sour service BHA products, the industry has had to develop and test new material chemistries and improved heat treatment operations to satisfy the new more aggressive drilling programs.
The use of HWDP is a result of modern drilling practices involving the need to taper the drill string. HWDP is a transition component that not only applies weight to the bit but also reduces the high bending stresses between the connections from the heavy, stiff drill collars to the light, flexible drill pipe. It offers an ideal location for the drill string's neutral point, the location where tension and compression stresses meet and cancel out.
Currently there is no API or ISO specification for sour service drill pipe. In response, the industry has established its own set of requirements. The IRP were developed in 1999 by a committee in Canada comprised of regulatory boards, operators, drilling contractors, manufacturers and rental tool companies to address the need for drilling component requirements to be utilized in applications where H2S is present. These requirements are a result of extensive field experience under severe H2S conditions.
The IRP2 have established specifications for hardness, material strength, and heat treatment processes along with material's chemistry recommendations for sour service applications. The mechanical specifications and chemical recommendations for sour service grades are listed in Table 1 and Table 2, respectively.
Archie's empirical law constitutes the basis of quantitative Petrophysics; however, the physical significance of this law is poorly understood. The issue involves substantial uncertainty in oil in place. Similarly, Carman-Kozeny's (C-K) relation is source of several permeability models. C-K is derived from Poiseuille's equation, applicable in laminar-viscous-flow in straight-uniform non-communicating tubes. Neither C-K nor Poiseuille's formulae consider inertial accelerations, non-Darcy flow, caused by changes in either cross section or flow direction occurring in porous media. Implications include sizeable limitations in permeability modeling.
Suitable hydrodynamic and electrical models can be created using fluid mechanics analytical methods. The models delineate the velocity and electrical potentials, streamlines and controls, represented by C-K and Archie's equations. This approach theoretically verifies both relations and reveals that:
The aim of this work is to show how Archie's law ceases being merely empirical and C-K becomes thorough, thus gaining a full physical conception of their power law behavior. As a result, revised Archie's and C-K relations are proposed for water saturation and permeability computations. Main applications comprise the generation of rock catalogs and synthetic production logs to assist in history matching.
Archie's and C-K are very popular/famous equations. Their usage is widespread despite a common lack of complete comprehension of these relationships.1 Different versions of Archie's and C-K equations exist. Their parameters adopt varied values based on simplifying assumptions, which affect the accuracy of water saturation and permeability estimates.
Both oversimplification and ambiguity, created by the diversity of Archie's and C-K equation forms, will be tackled first. Then, fluid mechanics and electric field similarities and differences will be analyzed, to quantify the influence of both the viscosity of the fluids and the geometry of porous media. This quantification is the main difficulty in permeability and saturation modeling, and in explaining fluid and electric flow. Since the analyses contemplate the connectivity among the different capillary routes, a brief discussion of pipe networks and flow regimes at pore-scale will be included.
Finally, electric and hydraulic models will be conceived to demonstrate amended versions of Archie's and C-K equations. Mathematical amalgamation of these relations will set the foundation of a theory-based permeability/rock type model, which includes the ingredients of dynamic surface area, pore throat/pore body dimensions, electric and hydraulic tortuosities, and fluid distribution. Discussion and validation of all these topics will follow.
This paper clarifies several phenomena: Archie's first equation responds to rock geometry only, because electric flow has no viscosity. Archie's second equation describes the distribution of water in partially saturated pores. Fluid viscosity effects, rock geometry, and various flow regimes simultaneously acting, govern hydraulic flow, hence C-K equation. All three equations relate to a microscopic description of the rock. Their coefficients and variable exponents physically represent tortuosities, which respond to the magnitude of "corner?? angles and reflect the change in direction of the bulk of the flow.
In hydraulic flow, the variable exponent reacts to both viscosity and change in direction. An efficiency multiplier handles the losses due to the changes in cross section of the fluid path, as it is stipulated for classic hydraulic components.
Arguments are presented to prove that resistivity and resistance are not quantitatively interchangeable as Ohm's law suggest. This has profound implications in shaly sand models. Emphasis is put in what the literature clarifies in a subtle manner: in electrostatic charge-free regions, Ohm's law must be complemented by Laplace's differential equation, whenever the shape of the conductors is not straight.
Over the last two decades many developments have enabled accelerated growth in horizontal drilling. Drilling technologies have pioneered these advancements, with current technology capable of drilling thousands of feet through a thinly bedded hydrocarbon reservoir. Completion advancements designed for extended horizontal wellbores have also advanced, albeit at a slower pace. Initially horizontal drilling was limited to naturally fractured reservoirs with simple open hole or slotted liner completions. This was due primarily to the ability of the reservoir to flow economically without the need for stimulation. Reservoirs requiring stimulation were initially not candidates for horizontal drilling. Developments in completion technology specific for horizontal wells have broadened the reservoirs where horizontal wells can be effectively stimulated.
When drilling a horizontal well, there are two completion options. First, the horizontal can be completed open hole, or with slotted/perforated liner. Effective stimulation along the horizontal wellbore is impossible. The second completion system requires cementing the production liner and running multiple isolation systems to effectively treat different sections of the wellbore. Multiple coiled tubing trips and multiple rig up and down of the stimulation equipment are required. These multi-stage horizontal completions take weeks to complete at high costs and elevated risks. Ultimately, the high completion costs or the lack of production due to ineffective stimulation make many reservoirs uneconomical to exploit.
This paper will discuss a new open hole completion system run as part of the production liner, does not require cementing and provides mechanical diversion at specified intervals, thus allowing fracturing and stimulations to be effectively pumped to their targeted zone. Details of the engineering design and testing will be specified, with elaboration on the applications and case histories were these systems have been successfully deployed. The case histories will detail the operational efficiencies of the system in conjunction with the enhanced production realized.
While horizontal drilling has progressed over the last decade to become the field development method of choice in many cases, there have been certain limiting technologies on the completion of horizontal wells that have proven to slow that growth. This is primarily the ability to effectively stimulate or fracture different intervals of the horizontal wellbore, particularly in reservoirs that were not naturally fractured. The use of limited entry and bullheading techniques provided little if any benefit compared to vertical wells. Post production analysis on the deliverability of horizontal wells in reservoirs such as matrix, heterogeneous and non-conventional formations showed a direct correlation to the completion and stimulation methods employed and their shortcomings in horizontal applications. Thus, the additional economics required to drill a horizontal well was not justified by the equal to or slightly better production results compared to vertical wells.
Horizontal completions where the wellbore is cased and cemented, effective stimulation techniques were addressed some years back by limited entry techniques and then later by the use of composite bridge plugs set on coiled tubing (CT), followed by perforating and then stimulating the well. The bridge plug provides the mechanical diversion in the liner to effectively stimulate each selected zone. This process is then repeated for the number of stimulations desired for the horizontal wellbore. After all the stages have been completed, CT is used to drill out the composite bridge plugs and establish access along the horizontal.1 Although effective, the inherent cost of multiple interventions with CT, perforating guns and deployment of fracturing equipment needed for each stage are extremely high, not to mention very inefficient and time consuming. This coupled with the associated mechanical risks often does not allow for the optimum number of fractures to be placed along a given horizontal interval. Production using this method can also be limiting, as cementing the wellbore closes many of the natural fractures and fissures that would otherwise contribute to overall production.
This paper presents an enhanced oil recovery (EOR) evaluation for two heavy-oil fields in Africa. The objective of the evaluation is to identify the technically and economically viable EOR techniques for the fields. A total of thirteen established and emerging EOR techniques were evaluated in this study. The study included the first degree approximation of the oil recovery for the viable EOR techniques and the stand-alone project economics estimation.
The data required for the study include: 1) fluids and rock properties; 2) driving mechanism; 3) production data; 4) OOIP and recoverable reserves; and 5) relative permeability curves. Various EOR technique screening criteria, consisting of a list of reservoir parameters and their ranges which are likely to lead to a success, were applied to match the parameters of the study fields. The oil recovery predictions were estimated utilizing general reservoir parameters and developed correlations1. The economic feasibility of the potential EOR techniques was then evaluated based on the stand-alone project economics that accounted for the revenue from the incremental oil and the associated operating and capital costs.
The evaluation results showed that the thermal EOR techniques: steam flooding and in-situ combustion are technically the most viable EOR techniques for the fields. It was then followed by the chemical EOR techniques. The performances of steam flooding and in-situ combustion are both very promising, with oil recovery of up to 49% OOIP. Comparing to the oil recovery of water flooding, a significant incremental oil recovery of 24% OOIP was obtained. However, the in-situ combustion process is able to accelerate the oil production, which significantly impacts the economic viability assessment, rendering the in-situ combustion process as the most technically, and economically feasible EOR process for the fields.
Based on the EOR evaluation, the oil recovery predictions and economic assessments of the thirteen EOR techniques, including the chemical, gas, thermal and microbial EOR techniques, served as a guideline to develop the long term corporate strategy regarding the EOR potential of the fields.
Gamma rays are bursts of high-energy electromagnetic waves that are emitted naturally by some radioactive elements. Laboratory experiments were undertaken to assess the influences of gamma irradiation on thermal decomposition and petrophysical properties of carbonate rocks of aquifers and oil reservoirs. A constant gamma ray dose of 9 MGy was applied on identical calcium carbonate core samples, extracted from actual oil reservoir. The core samples were analyzed using thermogravimetric analysis (TGA), differential thermal analysis (DTA), infrared spectrum (IR) and scanning electron microscope (SEM) before and after application of gamma ray irradiation. The attained data was used to interpret thermal decomposition, phase transition and mechanical stability of calcium carbonate rocks. Furthermore the effect of gamma irradiation on pertophysical properties of porosity and permeability were studied experimentally for water and oil saturated carbonate rocks.
Chemical composition of the carbonate core samples was determined using titration method and its sulfur content was determined using precipitation method. Application of Differential Thermal Analysis (DTA) proved the purification of the used core samples. Chemical analysis indicated that the core ha 99.8 % calcium carbonate. The Infrared (IR) indicated that no chemical changes of irradiated core samples have been observed. The analysis using DTA and TGA indicated that gamma irradiation enhanced thermal decomposition of carbonate rocks of oil reservoirs. The obtained results indicated that calcium carbonate rocks are stable rocks. In addition, the gamma ray irradiation has been proven to have almost no effect on porosity and permeability of these reservoir rocks.
Applications of the attained results are expected to have real impact on deep understanding of rock stability, using gamma ray tools and measuring gamma ray levels in oil fields, and improvements in future interpretation of attained data from gamma ray measurements such as gamma ray log.
Since their origin in 1912, wireline-conveyed logging tools have firmly established themselves as the industry preferred tools and often the only accepted formation evaluation method. Since its inception over 25 years ago, Logging While Drilling (LWD) formation evaluation measurements have been often viewed as correlation only. This "correlation stigma?? is caused by a number of factors including a lack of accounting for environmental effects, formation changes, and evolving tool capabilities. These issues are compounded by low resolution and sparse real-time data resulting from transmission rates that have been as low as 1/2 bit per second
This paper will review the fundamental differences in LWD and wireline conveyed measurements. It addresses the environmental corrections being applied to LWD measurements by the industry today; the positive effects that new drilling technology can have on the logging environment; the changes to the formation that occur between drilling with LWD tools and wireline evaluation; the advancements in realtime capabilities; the evolution of LWD tools that enable realtime formation evaluation; and the need to develop physical measurements in LWD.
Better understanding of these areas will allow direct well-to-well comparisons regardless of the method of conveyance of the formation evaluation measurements and will enable operators to make more informed decisions as to which technology applies best for each well environment.
Measurements While Drilling (MWD) tools were the first tools developed that allowed operators to read the wellbore without pulling out of the hole. Initially, they were used almost exclusively for directional purposes. Today, most clients and service companies still refer to logging suites as MWD. In order to differentiate, however, in this paper MWD will refer to tools that are utilized for directional purposes as well as data transmission and the LWD (Logging While Drilling) will refer to tools, which are used in formation correlation and evaluation.
When LWD tools were introduced, operators did not view LWD as a wireline replacement and used it as a formation evaluation option only as a "last resort??1. While being utilized more and more as the primary means for formation evaluation that stigma still persists for many a well. An article published by Oilfield Review in 1991 clearly defined where the industry had found applications for LWD, including:2
Even for these specific applications, the information being used for formation evaluation came almost exclusively from the recorded mode (RM) logs, which are generated after the tools have been pulled out of hole and the information is downloaded and processed.2
As shown in figure 1, Spears and Associates estimate that the LWD market has grown at an annual rate of 14% compared to 12% for wireline. The total worldwide, LWD market finished 2006 at just over $1.3 Billion, about 20% of the wireline $6.2 Billion dollar market.3
One reason that LWD has not been a trusted replacement technology is because it reads differently than the wireline logs. The measurements are fundamentally different, not only because of difference in the sensors taking the measurement, but because the wellbore itself is changing. Initially, these differences were not universally understood and poorly explained. Occasionally LWD companies were guilty of selling their vision concerning where a tool's capabilities are heading and not what it could do then on a specific well. LWD acoustic tools were the latest victims of this process. Major hardware changes, better job planning, field procedures,
and sustaining efforts occurring over the last few years have allowed this tool to reach previously envisioned potentials. For some clients who have already used these tools unsuccessfully, these efforts may be too late. It may take years before they are willing to risk using these tools again.
The gravity drainage and oil reinfiltration phenomena that occur in the gas cap zone of naturally fractured reservoirs are studied through single porosity refined grid simulations. A stack of initially oil-saturated matrix blocks in presence of connate water surrounded by gas-saturated fractures is considered; gas is provided at the top of the stack at a constant pressure under gravity-capillary dominated flow conditions. An in-house reservoir simulator, SIMPUMA-FRAC, and two other commercial simulators were used to run the numerical experiments; the three simulators gave basically the same results.
Gravity drainage and oil reinfiltration rates, along with average fluid saturations, were computed in the stack of matrix blocks through time. Pseudo functions for oil reinfiltration and gravity drainage were developed and considered in a revised formulation of the dual-porosity flow equations used in fractured reservoir simulation.
The modified dual-porosity equations were implemented in SIMPUMA-FRAC,1,18 and solutions were verified, with good results, against those obtained from the equivalent single porosity refined grid simulations. Same simulations, considering gravity drainage and oil reinfiltration phenomena, were attempted to run in the two other commercial simulators, in their dual-porosity mode and using available options. Results obtained were different among them and significantly different from those obtained from SIMPUMA-FRAC.
One of the most important aspects in the numerical simulation of fractured reservoir is the description of the processes that occur during the rock matrix-fracture fluid exchange and the connection with the fractured network. This description was initially done in a simplified manner and therefore incomplete.2,3
Experiments, theoretical and numerical studies3-6 have allowed to understand there are mechanisms and phenomena such as oil reinfiltritation or oil imbibition and capillary continuity between matrix blocks that were not taken into account with sufficient detail in the original dual porosity formulations to model them properly and that modify significantly the oil production forecast and the ultimate recovery in a naturally fractured reservoir.
The main idea of this paper is to study in further detail the oil reinfiltration phenomenon that occur in the gas invaded zone (gas cap zone) in NFR and to evaluate its modeling to implement it in a dual porosity numerical simulator.
Considering the reservoir to be a stack of matrix blocks (sugar cubes) according to the Warren and Root7 conceptual dual porosity model, the oil reinfiltration occurs when the oil confined in the upper blocks is expelled out of matrix blocks thru fractures and it reinfiltrates in the blocks below. This block to block oil flow occurs mainly because of the competition of the capillary and viscous forces.
The study was divided in two parts, firstly using a single porosity simulator a fine grid was built in the space occupied by the stack of matrix blocks and fractures allocating the particular characteristics and properties of each medium to the different portions that these systems occupy in the grid.
The phenomena that occur during the numerical experiment were studied. The capillary forces act only on the matrix blocks being zero in the fractures and the viscous forces are canceled out through the introduction of a very low gas injection rate through the top face of the stack; a flow process driven by capillary and gravitational forces only is established in this fashion. 8,9
In the fine grid simulation average gas and oil saturations are computed as time goes by for each one of the matrix blocks in the stack. Drainage and reinfiltration rates are computed through each one of the matrix block faces and their dependencies on the matrix block average gas saturations are established. Then the pseudo functions that are required in the modified dual porosity formulation are calculated.
Secondly, using the modified dual porosity simulator SIMPUMA-FRAC, a coarse grid is built of the same dimensions of the single porosity fine grid and the gravity drainage is simulated by using the matrix-fracture transfer pseudo functions that had been previously generated. Hence, the modified dual porosity simulator should reproduce the average behavior observed in the fine grid for the stack of blocks in the single porosity model.