Drilling optimal number of wells is a critical task in the development of hydrocarbon reservoirs. Most important data needed to accomplish such an endeavor are the well deliverability potential that depend upon two major factors; (1) reservoir characteristics such as porosity, permeability, stresses, connectivity, reservoir pressure, condensate content, field extent, heterogeneity, etc., and (2) drilling, completion, and stimulation properties that include vertical, horizontal, and multi-lateral well configurations, open-hole, pre-perforated casing, or cemented liner completions, and single or multistage fracture (MSF) assemblies either open hole or plug and perf (P&F). Developing a gas field optimally is a tedious process that requires the involvement of multi-disciplinary highly skilled engineers and technologists, to ensure that production target and estimated ultimate recovery (EUR) are realistic and met.
In tight reservoirs, where conventional completion is inadequate to provide economic gas rates to produce the reserves in a timely manner, hydraulic fractures and often MSF techniques are induced to enhance well rate and long-term production sustainability. For a field where drilling horizontal wells and completing them with hydraulic fracturing are required, a comprehensive development program addressing various drilling and fracturing options must be initiated. These include drilling directions, lateral lengths, and drill in fluid characteristics, and pumping and fracturing fluid and proppant properties.
Much work has previously been done to address well productivity and optimal well spacing. This paper presents some quick and simple analytical solutions associating well geometry to productivity improvement. The impact of reservoir permeability, vertical anisotropy, net pay thickness, horizontal well length, fracture half-length, fracture conductivity, the number of finite transverse fractures induced in a horizontal wellbore, and many other relevant parameters on well productivity are depicted in this paper. Although the results obtained from the analytical solutions are optimistic as that they do not consider damage or operational issues and lost time, the data serve as excellent references to qualitatively assess the impact of different completion types on reservoir performance.
From mathematical study and field performance analyses, it can be concluded that horizontal wells perform better than hydraulically fractured vertical wells in relatively thin reservoirs. In thick reservoirs, particularly where the vertical permeability anisotropy is high, fracturing is needed to ensure vertical connectivity of the layers with the wellbore through the created fractures. In such conditions, hydraulically fractured vertical wells deliver at rates higher than the un-fractured, horizontal wells. Depending on reservoir conditions and well completion properties, a horizontal well with MSF may perform the best. In summary, there may be numerous development scenarios that must be considered through modeling and pilot testing to derive an effective and efficient field development program.
Hydraulic fracturing is a widely used technology in the industry to enhance oil and gas production, particularly in tight formations. Tight gas and shale cannot sustain commercial production rates without fracturing. Although the technique has been used in the industry for many years and vast improvements have been made in upgrading fluid chemistry, proppant types, pump schedule sequence, and overall well completion system, a close evaluation is always required to ascertain that the fracturing has provided the level of productivity expected from the candidate well. Such evaluation and analysis will help improve and optimize the stimulation technique for any given reservoir and field conditions, address specific challenges in that area, and determine remedial plans on any well that did not show expected results in terms of productivity enhancement.
Saudi Arabian gas wells are usually stimulated to enhance and sustain production. Wells drilled in the R-1 reservoir in Field-A, that exhibit low to moderate permeability, are routinely hydraulically fractured. Many of these wells produce a high, sustained rate after a successful stimulation treatment. Some others do not perform up to expectation as seen from the rate decline. This can be caused mainly by inefficient fracture treatments such as achieving short half-length, limited vertical coverage, and poor post-frac cleanup. A critical and intense work on numerous wells has been performed using available data from geology, open hole logs, cores, pressure transient tests, etc., to understand and quantify reservoir characteristics, fracture properties, and flow capacity of these wells to come up with plans to improve productivity. Such plans include remedial treatments such as refracturing, placing additional perforations in previous unperforated intervals, initiating hydraulic fractures in different layers, and sidetracking the well to change its trajectory and geometry to contact new producing intervals. This paper summarizes the well conditions, complete evaluation processes, and suggests remedial procedures for each well to ensure full potential.
The primary purpose of hydraulic fracturing treatment is to enhance productivity. A successful treatment is characterized by numerous factors of which the most important ones are to connect the wellbore with the entire net pay thickness, perform excellent post-fracture cleanup, place high conductivity proppant, significantly improve well rate, and extend production sustainability. If the fracture treatments are mediocre or poor, the well productivity will decrease within a short period of time. Once it is identified that a well is not sustaining productivity to its expectation based of reservoir quality and designed hydraulic fracture treatment conducted, diagnostics work should be performed to properly evaluate the reasons for production decline. Subsequently, remedial measures should be planned and extensive modeling work conducted to confirm the ideal solution for reviving well productivity1-3.
Hydraulic fracturing is a widely used and proven technology in the industry to enhance oil and gas production, particularly in tight formations. Recent improvements in fracture fluid chemistry, proppant types, drilling strategy, and well completion technology have significantly contributed in optimizing reservoir and field development. Consequently, well evaluation and comprehensive analysis of reservoir parameters and production data is necessary to ascertain that the most appropriate stimulation treatment is selected to provide the level of productivity expected from the wells. The evaluation consists of assessing reservoir geology, open hole logs, pressure transient data, production performance, and reservoir fluid properties along with drilling and fracturing parameters. Such assessments help improve and optimize the stimulation technique for any given reservoir and field conditions, addressing specific challenges in that area, and determining remedial plans on any well that did not show expected results in terms of productivity enhancement.
Saudi Arabian gas wells are routinely stimulated to enhance and sustain production. The current strategy to drill horizontal wells and induce multiple hydraulic fractures has contributed to improved gas recovery. Due to the reservoir heterogeneity and challenges in creating optimal hydraulic fractures, some wells show high post-treatment production rate and fall into early decline.
A critical and intense work on the underperforming wells has been conducted using data mainly from geology, open hole logs, cores, fluid properties, and pressure transient tests to understand and quantify reservoir characteristics, fracture properties, and flow capacity of these wells and come up with plans to improve production. Evaluations of many wells are depicted in this paper where expected production was not achieved. The results have shown that short fracture half-lengths, limited vertical coverage, and poor fracture fluid cleanup are some of the main contributors to suboptimal post-fracture productivity. The main remedial plans to restore well productivity included the addition of perforations, re-perforations and refracturing. The refracturing treatments are designed different than the initial treatments to include some of the newer fracturing fluids, perforation strategy, and pumping schedule. This paper summarizes the well conditions, complete evaluation processes, and the remedial procedures undertaken for each well to ensure full potential. Pre- and post-remedial action program indicates the success of refracturing program.
Heterogeneity and tightness of carbonate retrograde reservoirs are the main challenges to maintain gas well productivities. The degree of heterogeneity changes over the field and within well drainage areas where permeability decreases from few millidarcies to less than 0.2 md. Thorough studies have been conducted to exploit these tight reservoirs and not only focused on well performance, but have extended to assure enhancing and sustaining gas productivity through practical applications of technologies. The main objective of this paper is to assess the performance of Multi-Stage Fracturing (MSF) in horizontal wells that were drilled conventionally and did not meet gas deliverability expectation. This paper gives a detailed analysis of well performances, exploitation approaches, and successful implementation and optimal cases to utilize new completion technologies such as horizontal multi stage fracturing to revive low producing gas wells due to reservoir tightness. Placing the horizontal wellbore reference to the stress directions plays a major role in the success and effectiveness of fracturing in enhancing and sustaining productivity.
Several wells have been drilled in tight reservoirs, but could not achieve or sustain the target gas rate. Recently, two wells were geometrically sidetracked targeting the development intervals based on logs of the original hole and completed with MSF toward the minimum stress direction. Open hole logs showed a low porosity development similar of the vertical holes. However, after conducting multiple stages fracturing, both wells produced a sustainable rate of more than 25 MMSCFD that prompted to connecting them to gas plants. Placing these sidetracks in the minimum stress direction helped to create transverse fractures that connect to sweet spots and sustain gas production. This paper provides thorough guidelines for selecting optimal candidates for MSF based on reservoir heterogeneity, proper design and execution of fracturing. It also addresses various components that contributed to the success of both wells, such as reservoir development, workover pre-planning, geo-mechanics studies, drilling operations and real-time support, completion operations optimization and best-practices, and performance evaluation of other producers in the field. The paper also includes essential recommendations for development of tight gas reservoirs.
Saudi Aramco is developing several gas fields in the Eastern Province of Saudi Arabia by drilling horizontal wells in the Khuff and pre-Khuff tight carbonate and sandstone formations. To date, many wells have been drilled in the maximum horizontal stress direction with virtually no wellbore instability occurring during the drilling operation. When these wells are hydraulically fractured, the fracture grows along the wellbore in the direction of well azimuth. To avoid overlapping of two adjacent induced fractures and thereby communication between stages, only 2-3 multi-stage fracture treatments can be performed. Depending upon the length of wellbore-reservoir contact, reservoir development, and stress barriers, more than four fracture treatments can become redundant or even cause premature screen-out in proppant fracture treatments.
Wells drilled in the direction of minimum horizontal stress are potentially more favorable from the perspective of reservoir development and optimal production. In such a situation, hydraulic fractures grow transverse to the wellbore axis allowing multiple fractures to be placed without the possibility of fracture overlapping. Consequently, few wells that have been drilled in the minimum horizontal stress direction encountered several drilling-related problems, such as stuck pipe, breakouts, and breakdowns. A comprehensive study was conducted to overcome the wellbore stability issues and investigate feasibility of drilling wells in the minimum horizontal stress direction. Correct mud weight (MW) prediction is one key factor during the drilling stage to keep the wellbore stable and deliver good borehole geometry to run multi-stage fracturing assembly without complication. Multiple transverse hydraulic fractures easily created in such wellbore geometry maximize reservoir contact area and increase productivity of the low quality tight reservoir.
The key objectives of the study were to define a safe MW program for the horizontal section of the planned wells by conducting a wellbore stability study, and to determine a real-time strategy to mitigate and/or manage wellbore instability problems as they arise. The scope of work included root cause analysis of drilling events, development of Mechanical Earth Models (MEM) for offset wells, integrating sections of the mechanical earth model from the offset well to the planned well trajectory and a safe MW program for planned well.
Al-Anazi, Hasan D. (Saudi Aramco ) | Al-Qahtani, Adel A. (Saudi Aramco) | Rahim, Zillur (Saudi Aramco) | Masrahy, Mohammed (Saudi Aramco) | Al-Malki, Bandar H. (Saudi Aramco) | Al-Kanaan, Adnan A. (Saudi Aramco)
The Unayzah reservoir in SA-1 field is highly unconsolidated with heterogeneous sequence of Permian and Devonian sandstones saturated with condensate rich gas. Reservoir characterization based on the seismic, geological, and petrophysical analysis has indicated many stratigraphic units within the main Unayzah-A interval, which consists of well developed Eolian sandstones and closely associated inter-dune and lacustrine deposits. Due to the unconsolidated nature of reservoir rock, conventional drilling and completion pose a very high risk of producing formation sand along with gas production, which can cause immense damage to production string, wellhead, surface flow lines, and gas plant equipment. In the early development stage of SA-1, frac-pack (F&P) was used and had been successful for several years. The method consisted of creating a short fracture, packing it up with proppant, and placing a screen as part of the completion system across the reservoir section. After years of producing from wells completed with this F&P completion, the scale due to fines migration buildups in the proppant within the annulus and causes high positive skin and deterioration of the screen, and consequently, needs a complete workover to regain lost potential. The workover for a F&P well is nothing less than drilling a new sidetrack as the completion cannot be de-completed and pulled out.
After detailed study and modeling, it was decided to change this strategy and complete the wells with an expandable sand screen (ESS). The completions using the ESS were effective and successful in terms of trouble-free deployment of the equipment and sustained a long-term sand-free rate.
The CSS assembly has also been used in this reservoir. The initial test of this equipment conducted in one of the high producers was successful; however, long-term sand-free production as well as maintaining screen integrity cannot be ascertained. Among the disadvantages of CSS completion is the possibility of wellbore collapse on the screens with the depletion of reservoir pressure (changing near-wellbore stress environment) during production life of the well. In such case, the screen can incur partial or total damage and can no longer resist sand production.
The paper describes in detail the reservoir characteristics and presents numerous examples of different completion methods implemented in the field to prevent sand and ensure high, sustainable flow rate. Long-term performance data are analyzed and presented in this paper to show the performance of sand screen technology.
In any field development, it is important to identify reservoir structure, heterogeneity, rock properties, and fluid characteristics to lay down an optimal development strategy to enhance production and increase recovery in the most cost-effective way. As such, detailed reservoir description and characterization using geophysical, geological, and engineering data are required. This paper discusses how a condensate-rich, high flow-capacity, and high-sanding deep gas reservoir was gradually developed and optimized to select the most appropriate drilling and completion technique using available geological, geomechanical, and reservoir data.
Saudi Arabia's SA-1 field produces from the 'Unayzah formation which is Permian in age and is subdivided into three stratigraphic units. The lower 'Unayzah-B and C units present in the SA-1 area are dominated by generally tight, quartzose sandstones with rare siltstones intervals that are ascribed to deposition in lake fluvial-dominated environments. The 'Unayzah-A comprises of sandstones and variable amounts of siltstones that were deposited in arid, eolian-dominated environment. 'Unayzah-A is prolific, offers high reservoir quality, and is prone to sand production due to its highly unconsolidated nature. The first well drilled penetrating 'Unayzah-A in 1997 showed excellent reservoir development. Cores were collected from this well and subsequently from other wells which confirmed unconsolidation of reservoir rock with low Young?s modulus and compressive strength values.
To avoid sanding during production, the wells were initially completed vertical with fracpack stimulation using premium screens. Even though some difficulties were encountered during fracpack installation, the strategy was used in the first few wells. With the advancement of technology both in drilling and completion, the development method was gradually shifted to drilling horizontal and highly slanted holes. This method eliminated deploying the fracpack system, substantially increased reservoir contact, and proved higher well performance. To protect well integrity and eliminate sand production, premium expandable sand screens (ESS) were selected for completing the wells. The overall strategy significantly improved the SA-1 field development program. Higher sustained gas rates were achieved due to reduction of non-Darcy skin, sanding was eliminated, and risk related to deployment of completion equipment (ESS) was reduced. ESS completions are attractive in open-hole completions for their easy-to-use applications, and since they have no proppant or sand-pack filter system that resulted in low or zero skin factor.
Currently, the SA-1 field is producing with wells that have high rates, on the order of 20-30 million standard cubic feet per day (MMscfd). With a high condensate level in this field (more than 400 bbl/MMscf), the wells have experienced a low to moderate decline and the reduction in reservoir pressure has been steady and within expected limits. Improved reservoir contact from horizontals has decreased pressure drop near the well, decreased the rate of condensate dropout, and has improved overall well potential and reservoir performance. Initially drilled vertical wells that are facing some production decline due to deterioration of fracpack screen and proppant conductivity are now being sidetracked and completed with an ESS system.
Afsari, Meisam (Iranian Offshore Oil Company) | Amani, Mahmood (Texas A&M U at Qatar) | Razmgir, Seyed Ahmad Mohsen (Iranian Offshore Oil Company) | Karimi, Hassan (Schlumberger) | Yousefi, Saman (National Iranian Drilling Company NIDC)
Drilling through subjected mature offshore oil field is made more challenging by problems arising from wellbore instability, mud losses, excessive cutting, tight hole, stuck pipes and kick/flow zones for last few years. These problematic layers have caused quite a significant NPT (non productive time) during drilling.
For better understanding of factors causing wellbore instability problem and to predict mud weight window to be used for future wells, construction of mechanical earth model (MEM) was essential.
Mechanical Earth Model (MEM) is a numerical representation of the state of stress and rock mechanical properties for a specific stratigraphic section in a field or basin2.
In this study main drilling problems for each drilling interval in this field were described afterward different stages for construction an 1D Mechanical Earth Model (MEM) for the field was established. It was then demonstrated that how 1D MEM could be used to predict and prevent the common instability problems encountered during drilling.
For making MEM different sources of data including, drilling data, formation evaluation data, well testing, etc were used.
After making MEM for the field, safe and intact mud weight window was determined and according to that, suggestions for optimum mud weight for stable borehole on each interval was made.
MEM for this field can now be used to predict not only the safe mud weight window and possible drilling hazards, but can also be used for studies like reservoir compaction, sand production, and perforation stability and so on.
The subject field is located in central part of the Persian Gulf and its structure is result of salt tectonic. On this domal structure, several faults trends of NW-SE are visible on the seismic data which have produced some grabens. Most sections of the stratigraphic column are dominated by carbonates with thin lamination of shales and evaporate except one sandstone layer. 3D geological view of the field is shown in Figure1.
This field has been experiencing some drilling problems for last few years. Mud losses, excessive cutting, tight spot, stuck pipes, and kick/flow zones are some of the commonly occurred problems. Some stratigraphic levels have been quite difficult to drill through, which has caused quite a significant NPT (non-productive time). In some cases, side-track holes had to be drilled from the original hole. Generally, it is not so easy to predict what kind of problem the well would get into.
Minimizing the risk of problems related to geomechanical properties requires understanding the geomechanics of well construction and field, In order to be able to address the drilling problems and propose the solutions for the future wells which could optimize drilling and production performance of the subject field.
Here the methodology of building a MEM is presented. Generally geomechanical model relates dynamic elastic properties to static equivalents. These elastic static properties are then used to characterize formation strength and in-situ stress4. The MEM consists of depth profiles of elastic or elasto-plastic parameters, rock failure mechanisms, geologic structure, stratigraphy, well geometry, earth stresses, pore pressure and stress direction. After construction, this model can be used to identify geomechanical problems and to consider those problems for planning future wells.
Razi, Samin (Amirkabir University of Technology) | Shadizadeh, Reza Seyed (Petroleum U. of Tech Iran) | Shahriar, Kourosh (Amirkabir University of Technology) | Kazemzadeh, Ezzatollah (NIOC Rsch Inst of Petr Industry)
Asmari formation in Mansuri oil field is a complex geological environment. Variation in proportion of different lithologies (sandstone, limestone, and dolomite) in this formation poses serious challenges to drilling and production management, and makes it difficult to evaluate lithological and geomechanical characteristics of reservoir formation.
Wellbore instability and formation damage could substantially decrease drilling and production efficiency. Drilling of Asmari formation is almost always accompanied with mud loss causing damage to the reservoir formation. With developing a consistent mechanical earth model, an appropriate mud weight window is suggested based on formation strength and induced stress along the wellbore. Choosing an optimum mud weight would prevent fracturing the reservoir and losing mud into formation. Hence, drilling time and production rate of Asmari formation would improve considerably.
In this paper, laboratory testing on cores such as triaxial compressive test and ultrasonic test under confining pressure of reservoir provides experimental data to establish precise correlation between compressional and shear velocity and calibrate dynamic elastic properties resulting from sonic and density log. In addition, static elastic properties and mud logging data is used to assess induced stresses due to drilling of the formation. As a result, an accurate geomechanical model is constructed in minimum error since a complete set of data required to perform a proper evaluation is available. In addition, numerical modeling as well as analytical one is employed to analyze stresses and strains around the wellbore, especially in complex, heterogeneous areas.
Suggested mechanical earth model helps petroleum engineers evaluate geomechanical characteristics of reservoir formation in spite of its natural heterogeneity, make field development and well construction decisions accurately, and overcome the challenges of this complex area throughout the life of the field.
The process of drilling the 12 ¼-in. section in the deep Khuff field offshore Abu Dhabi is challenging because of an intricate geological sequence. This sequence consists of carbonates (limestone and dolomite) and anhydrite that are interbedded with shale and sandstone.
In the past, the operator, ADMA, has attempted to efficiently drill the section by using roller cone tungsten carbide (TCI) and polycrystalline compact (PDC) technology. PDC bits yielded a better performance in terms of penetration rate and durability in comparison to the TCI bits. However, because several PDC bits were required to drill the section, the amount of time required for drilling and tripping at a relatively deep interval increased. The increased time exposes the well to many risks that could occur as a result of tripping in a long open hole interval. To reduce the time and risk factors, additional analyses were performed that led to the creation of an optimum PDC design and established new benchmarks in the field at the first trial.
The objective of the study was to minimize the number of bit trips by enhancing the PDC bit performance and bit durability to drill longer intervals with a higher rate of penetration (ROP). Meeting this objective required a new PDC technology in conjunction with optimized motor drive. To address the challenge, ADMA, the bit vendor, and other service companies worked together to seek an optimized solution to drill this section efficiently.
This paper reviews the findings of the detailed study in drilling the 12 ¼-in. section in typical deep Khuff wells. The study shows that PDC damage from encountering harder stringers was the primary impediment to achieving better performance. The challenge was overcome by implementing a new cutter technology and drilling simulation software to optimize the cutting structure design.
The improvement that occurred in Umm Al-Shaif field is demonstrated by comparing the performance of the most recent well, in which the new technologies have been implemented, to the performance of earlier wells to illustrate the significant savings in time and eventual drilling cost.
This paper focuses on achieved performance and economic savings in the 12 ¼-in. section in Umm Al-Shaif offshore field in which ADMA develops deep Khuff gas wells in United Arab Emirates.
The 12 ¼-in. section is drilled from the Hith formation, which is encountered at 9,000 ft depth average, down into the Upper Khuff formation. This drilling interval crosses ten different formations, and the section length ranges between 5,500 and 6,400 ft. The section is drilled tangentially, with an inclination of 30 to 35 degrees, with medium speed positive displacement motors (PDM), but other driver mechanics, such as rotary steerable systems (RSS) and turbines, were used in previous wells. The turbine performance in this field as driver mechanisms was studied by Salman and El Raggal (1999).
Until recently, the bit types used to drill this section consisted primarily of PDC drill bits with varying design and cutting structures; however, the performance of most of the bits was less than planned in terms of footage drilled and ROP. Several bits failed prematurely, which resulted unplanned trips and the use of additional bits (Salman and El Raggal 1999). As shown in Table 1, Well X, drilled several years ago, used eleven bits to drill the interval, with an average of 360 ft drilled per bit. Most of the bits were pulled out of the hole because of low ROP, and most of the PDC bits showed severe cutter damage.