This challenging reservoir characterization case study is defined by the interaction between two reservoirs with different production mechanisms: a fractured basement reservoir and an overlying sandstone reservoir. The existing static geologic concept has been significantly enhanced by integrating pressure data from a unique three-year shut-in period to aid modeling of fractured reservoir connectivity. Previously, the seismic dataset was predominantly used to model the fault and fracture network and guide well planning. In the current approach, the full field data set, including all drilling parameters and new reservoir surveillance data were integrated to address uncertainty in the connected hydrocarbon volume and the relative importance of each production mechanism. The result is a reservoir management tool with which to test re-development concepts and effectively manage pressure decline and increasing gas/oil ratio (GOR) and water production.
To achieve a fully integrated history matched model, the first step was to make a thorough review of the existing detailed seismic interpretation, vintage production logging tool runs (PLT's), wireline logs (including borehole image logs (BHI)) and drilling data to find a causal link between hydraulically conductive fractures and well production behavior. In parallel, a material balance exercise was run to incorporate the new pressure data acquired during the field's shut-in period. The results of the material balance analysis were combined with seismic and well data to define the distribution of connected fractures across the field. Additionally, the material balance analysis was used to determine the connected hydrocarbon volume, the distribution of initial oil in-place and the relative hydrocarbon contribution from each production mechanism.
The field is covered by multi-azimuth 3D seismic and 43 vertical to highly deviated development wells, providing significant static and dynamic data for characterizing the distribution of connected fractures. Despite this high quality, diverse and field-wide dataset, prior modeling iterations struggled to sufficiently describe the production behavior seen at the well level. This has resulted in a major challenge to predicting the production behavior of new development wells and planning for reservoir management challenges. Capturing the complex interaction between production variables (including lithology, matrix versus fracture network, geomechanical stresses, reservoir damage and pressure depletion) at a field level instead of at an individual well level resulted in a unified static and dynamic model that reconciles all scales of observation.
This oilfield represents a unique reservoir characterization opportunity. The result is a key example of how iterative, integrated geological and engineering driven reservoir modeling can be used to inform the development in a complex, mature field. This case study provides an excellent analogue for the reservoir characterization of other fractured Basement fields and/or Basement-cover reservoir couplet fields in the early to late phases of their development.
Geochemical analysis of rocks is fundamental to the understanding of geology and earth sciences. X-ray dispersive spectrometry and other automated techniques are increasingly being used to determined and quantify the abundances of the major, trace elements and other rock properties. This study utilized a combination of dispersive spectrometric techniques (MicroXRF) and impulse rebound hammer method to establish links between geochemical and mechanical properties of rocks through a non-destructive method. MicroXRF has high resolution and can detect trace elements within the parts per billion range. The micro-rebound hammer was used to generate a reduced Young's modulus (E*), which gives a measure of the rock strength with negligible impact on the rock itself.
In order to explore, visualize and understand the dataset generated, principal component analysis (PCA) was applied to emphasize variation and bring out strong patterns in the dataset. The first two dimensions of PCA express 57.09% of the total dataset inertia; that means that 57.09% total variability in the data is explained by the planes/dimensions. The first dimension, which showed a strong positive correlation to clay forming minerals and rock strength, was tentatively identified as the clay gradient. The second dimension describes diagenetic alteration processes responsible for the enrichment of elements such as Ni, Mo etc. Further, a positive correlation was established between E* and four elements Cobalt (Co), Strontium (Sr), Titanium (Ti), and Zircon (Zr). Remarkably, Silicon (Si) had a negative correlation with all elements but positive correlation with porosity and permeability. We therefore identified Co, Ti, Sr, and Zr as proxy for the determination of rock strength specific for studied samples and proposed a workflow based on our sequences of analysis and interpretation. Furthermore, we identified four chemo- mechanical facies through hierarchical clustering of the product of the PCA.
This presented methodology could be specifically useful for geomechanical characterization of rocks; a key requirement needed for in-situ stresses estimation, wellbore stability analysis, reservoir stimulation and compaction, pore pressure prediction, and more importantly for characterizing drill cuttings where size and time are limiting. Drilling operations require constantly evolving cost effective and time efficient techniques, the proposed workflow will serve these purposes i.e. rapid determination of elemental composition (microxrf) coupled with E*will give a reliable proxy for rock strength. The technique can be applied to, drill cuttings, slabs and whole core directly without prior sample preparation.
Geomechanical characterization of subsurface rocks is important for many applications throughout the asset life cycle such as borehole instability, pore pressure prediction, seal breach and fault reactivation, drill bits and drilling parameters selection, sand production, hydraulic fracturing, and reservoir compaction (Meyers et al., 2005; Klimentos, 2005; Germay et al., 2017). A key component of Geomechanical characterization is the model calibration with reliable core data. Typically, core data calibration is performed using triaxial tests data output, such as the uniaxial compressive strength (UCS) and elastic properties of rocks (Young's modulus, Poisson's ratio, etc.), that are empirically linked to wireline data. Sample availability, representativeness, time, and cost are problems associated with core-based rock measurements for mechanical properties [3; 4]. There is also the issue of uncertainty associated with upscaling laboratory generated data with wireline data. Core-based measurement output is usually very limited, hardly constitutes statistically representative data as compare to large data from wireline logs, making it difficult to generate a reliable empirical correlation. Another issue is the inherent heterogeneity in rocks, which varies from nano to field scales. This makes establishment of empirical relationship between scattered core data and wireline data a subjective task. Even rocks that appear identically twin in bulk properties can vary widely in microstructure. Characterizing such reservoir-scale heterogeneities requires statistically representative data and the problems associated with core-based measurement make such substantial number of data points requirement an abominable.
The Permo-Carboniferous reservoirs of central Saudi Arabia comprise important accumulations of natural gas and light oils. Some of the reservoirs exhibit low resistivity and low contrast resistivity (LRLC) phenomena. Low resistivity pay reservoirs often produce gas/oil with little or no water at very low resistivities. Low contrast resistivity pay zones, on the other hand, produce hydrocarbon at minimum resistivity contrast between hydrocarbon-bearing intervals and adjacent water-wet or shaley zones. Evaluating these types of reservoirs poses a major challenge to petrophysicists and petroleum engineers due to the difficulty in recognizing them on logs and quantifying their hydrocarbon potential when using simple resistivity-based petrophysical models. As a result, potential pay zones can be incorrectly evaluated or bypassed. The objectives of this study, therefore, are: 1) to understand the causes of LRLC pay in the study reservoirs through a detailed assessment of the textural and mineralogical composition of the rock, and 2) to validate a simple porosity-based methodology for recognizing LRLC pay in both old and new wells.
To achieve the set objectives, 38 core samples and 107 thin sections were selected from two wells exhibiting low resistivity (Well-1) and low contrast resistivity (Well-2) phenomena, for detailed petrographic and mineralogical studies (SEM/XRD). Furthermore, a water salinity map was created to provide general salinity trends in the area. Well data combined with results of mineralogical and petrographic studies suggest that low resistivity and low contrast resistivity pay in the study reservoirs is the product of a complex mix of: 1) clay mineral types and its mode of distribution, 2) thin reservoirs below resistivity tool resolution, 3) significant grain size variation and microporosity, and 4) variable formation water salinities.
This paper highlights the causes of low resistivity and low contrast resistivity phenomena in reservoirs in central Saudi Arabia. Furthermore, the applicability of a porosity-based methodology for recognizing LRLC phenomena was verified with promising results.
The Unayzah reservoirs are Late Carboniferous-Early Permian in age and represent deposition under variable climatic conditions in different depositional environments. The deposition of the lower Unayzah reservoirs commenced in late Carboniferous to early Permian during the global Late Paleozoic Ice Age. They comprise glaciogenic deposits of the Juwayl Formation and are divided into two members: Ghazal Member and Jawb Member. The upper Unayzah reservoirs are found in the Nuayyim Formation, which consists of post-glacial sandstones and siltstones representing a number of depositional facies of variable reservoir quality which in general indicate an arid to semi-arid depositional settings. Depositional environments in the Nuayyim Formation include ephemeral (playa) lake, ephemeral fluvial, tidal flats, estuarine, nearshore marine, and eolian environments. In Central Arabia, Unayzah reservoirs are prolific oil and gas producers and their characterization is important for production and development. This study was aimed at identifying, characterizing and understanding facies and depositional environments distribution to produce a robust depositional model for these reservoirs.
Detailed description and facies analysis of over 6,300 ft of Unayzah reservoirs core were carried out. The lithofacies were grouped into facies associations, representing depositional environments. Stratigraphic correlation was performed using core and logs to discern vertical stacking patterns and establish lateral continuity.
The highly variable depositional environments that were identified indicate a dramatic change in climatic conditions during the deposition times, from glaciogenic deposits in the lower section into much warmer, arid environments in the upper part of the formation. The Ghazal Member is highly variable in thickness and represents glacial valley deposits. The Jawb Member is more widely spread in the study area and consists of more variable facies than the Ghazal Member. The Nuayyim Formation contains post-glacial deposits that are more complex and variable across the study area.
The results of the study contribute to the understanding of Unayzah reservoirs not only in Central Arabia but also in Eastern Saudi Arabia. It also provides new insights into the facies architecture and stacking patterns of the encountered depositional environments.
The N M gas-oil separation plant-1 (GOSP-1) is a typical GOSP, with one high pressure production trap (HPPT), one low pressure production trap (LPPT) and a gas compression and dehydration facility. The processed crude oil in N M GOSP-1 comes from a natural driven field (N M field) and consists of high gas-oil ratio (GOR) wells and low GOR wells. The crude oil in N M is classified as Arabian Super Light (ASL) crude oil and is stabilized in a separate downstream facility (Pump Station-3) before being pumped to export. The ASL stabilizer at PS-3 experienced excessive gas flaring and a taskforce was formed to find opportunities to reduce the flared gas. As the exclusive supplier to the stabilizer, we started to apply different scenarios to help in reducing the ASL stabilizer flare by maximizing gas recovery.
As part of the KhPD initiatives to optimize production from its facilities, an optimization study was carried out by the KhPD Plant Engineering Unit to explore the possibility of recovering extra amounts of associated gas from the N M GOSP-1 through operational optimization practice. The study was assessed initially using process simulation, Aspen HYSYS, to determine its viability. The field test was then carried out, which confirmed the simulation that an additional gas recovery of around 1 million standard cubic ft per day (MMscfd) was achieved. This was accomplished by reducing the LPPT operating pressure to 40 psig instead of the design pressure of 50 psig and managing production from the different GOR wells. This achievement transformed the issue of excessive flaring into an added revenue opportunity.
This paper describes the optimization study that was carried out to recover this amount of gas, in addition to its impact on reducing excessive gas flaring in the ASL stabilizer at PS-3 at zero investment costs.
Al-Humam, Abdulmohsen A. (Saudi Aramco,R&D Department) | Rizk, Tony Y. (Saudi Aramco,R&D Department) | Sunner, Jan A. (University of Oklahoma, Department of Botany and Microbiology) | Beech, Iwona B. (University of Oklahoma, Department of Botany and Microbiology, University of Portsmouth, School of Pharmacy and Biomedical Sciences )
This paper reviews some of the Saudi Aramco R&D Projects for increasing the asset life expectancy of its production facilities. The ultimate objective is to deliver innovative solutions to address actual or anticipated problems encountered by operations. The Research and Development Center in Saudi Aramco has developed a generic delivery model consisting, for each project, of the identification of the following four main components: business need, value created, internal competencies and partners to provide solutions in a timely manner
The portfolio for the Upstream R&D Program for the production facilities is composed of several projects:
This paper will summarize the goals and deliverables of these projects. Further potential R&D projects for Production or Midstream related issues are also listed.
Drilling horizontal wells is a common practice for Saudi ARAMCO in most of its oil and gas reservoirs of Saudi Arabian clastic and carbonate fields. A comprehensive study of rock mechanical properties with detailed analysis of the in-situ stress field was conducted to evaluate well stability during drilling and completion across a friable eolian oil-bearing sandstone reservoir. This paper discusses the application and implementation of the study to successfully drill and complete development horizontal wells in a challenging sandstone reservoir.
All horizontal wells were completed with different type of sand screens including Premium and Expandable Sand Screen (ESS). It is vital to obtain a near-gauge hole during drilling for a maximum stability of the screen during the life of a well. It is therefore important to prevent excessive compressive shear failure at the wellbore wall and avoid instability problems during drilling and completion. Therefore, an optimum confining pressure to the wellbore surface needs has been derived. The recommended mud type and weight windows derived from the study have been employed while drilling producers but not with injectors. The correlation between the mud weights and the in-situ stress magnitude will be discussed.
Well stability during drilling and long term screen integrity is dependant on the well azimuth relative to the in-situ stress field. The azimuth of the maximum horizontal stress, SHmax, was determined to generally line up in the E-W direction. The wellbore stability problems experienced in this direction as well as those drilled normal to it (i.e., N-S), will be addressed.
In regards to stability of very weak and friable formation intervals (such as those encountered in the, dunes and sand sheet facies), the operational practices are focused on creating gauged hole with least erosion effect as a critical measure to deploy the ESS; thus, ensuring successful completion and sustained production. The effect of mud on rock strength was evaluated during the foregoing study; therefore, results from using oil-base mud will be discussed and compared to results from the wells drilled with water-based mud.
refai, ibrahim Meselh (Schlumberger) | Assal, Anwar Ahmed Maher (Schlumberger) | Fould, Jeremie Cyril (Schlumberger) | O'Rourke, Tim (Saudi Aramco) | Haque, Muhammad Habib (Saudi Aramco) | Sayed Akram, Nawaf Ibrahim
A number of the wells reach there economical production limit and are consequently abandoned or mothballed until viable solutions are available to enhance there production to an economically feasible level. The Hawtah field (see Figure 1) discovered in the late 1980s is located 180 km south of Riyadh, the capital of Saudi Arabia (figure 1).
Hawtah is one of several small fields located along the Hawtah Trend (others are Ghinah, Hazmiyah, Nisalah and Umm Jurf). The Trend runs approximately 30 km east to west and 50 km north to south. Production in Hawtah comes from the Unayzah sandstone and consists of Arabian super light (50° API) sweet crude oil.
Hawtah field is a mature and depleted reservoir, and in order to maintain economical levels of production a combination of several technologies is being applied.
Due to the poor natural production from the vertical cased and perforated completions in Hawtah and little associated gas, electrical submersible pumps (ESPs) have been used in Hawtah to enhance production since early 1990's.
Existing wells are standard 9-5/8?? vertical cased wells with perforations through the thin producing interval with ESP set in the same casing. Due to the low productivity of this type of completion, and high water cut a work-over program was initiated by Saudi Aramco in the late 90s to re-complete these wells as horizontal producers using various sand control techniques.
While converting from vertical, cased and perforated wells to single horizontal producers has helped to improve production, multilateral wells are needed in Hawtah to achieve and maintain economical production rates from these wells. In addition sand control solutions are required to safely deploy several branches off one main vertical well.
This paper will describe the history of the well HWTH-34 and workover's performed during its life span. It will also discuss the latest achievement deploying Saudi's first TAML Level 3 multilateral completion of a tri-lateral well.
Well History - Introduction
HWTH Well No. 34 was drilled to a total depth of 6,662' and completed on 11-03-1991 as a vertical cased and unperforated oil producer in Unayzah reservoir. The well was then suspended with cement plugs and the wellhead blind flanged. The 7" liner was run and cemented from 6661' to 4907' with 100% circulation.
WORKOVER No. 1: was completed on 10-30-93. Cement was drilled out and well cleaned to 6563' (PBTD). The Unayzah reservoir was perforated with 4-1/2" TCP Guns selectively from 6264' to 6392'. The well was completed with a new ESP with bypass assembly ran on 3-1/2" EUE x 4-1/2" VAM tubing.
This paper discusses the first well in which an expandable screen and expandable liner hanger were installed in a horizontal openhole well for Saudi Aramco. Wells in this area require sand control; however, alternative sand control solutions presented some potential problems in the Saudi Aramco wells. Supporting the borehole by packing the annulus space with gravel to prevent pockets in the screen/openhole annulus is a viable solution in some sand control environments; however, Saudi Aramco decided to investigate an expandable sand screen that has an expandable steel base pipe designed to protect the wellbore from collapse and maintain screen integrity. This screen design is considered to be the strongest in the market, with 2,500 psi collapse strength. The screen is run inside the open hole, and after expansion, the screen extends to an outer diameter that is equal to the openhole inner diameter.
The case history data will include the completion design process and a description of the successful deployment of 1,310 feet of the expandable screen into the horizontal lateral. Before expanding, the screen O.D. was 5-3/8 -in, and after expansion, it had enlarged to the open hole ID of 6-1/8-in. This expandable deployment is significant as it was not only the first application of expandable, rigid, perforated base-pipe screen in the Middle East, but it was also the longest deployed to date for this type of 6-1/8 -in. expandable screen worldwide. This application was also the first completion in which an expandable liner hanger was used in the same well as an expandable screen in the Middle East.
The well has been put on production and has shown excellent productivity as well as sand control.