The Jilh formation (JILH) is a tight, predominantly dolomitic Triassic formation occurring from 8,000 ft true vertical depth (TVD) to 10,000 ft TVD across the Ghawar field in Saudi Arabia. Drillers experienced extremely high pressured saltwater, oil and/or gas flows in about 20% of the wells that traverse it. The highest recorded flow rate from the JILH was 25,000 barrels per day (BPD) of saltwater and the highest mud weight required to control the JILH flow was 164 pounds per cubic foot (pcf) (22 ppg). The majority of the observed flows have been saltwater, which required a mud weight of 120 pcf to 155 pcf (16 ppg to 20.7 ppg) to control the well. This unpredictable nature of the JILH flow has not only mystified the drillers, but also plagued them across the Ghawar field. If abnormal pressure is encountered in the JILH, a casing string is required to isolate it prior to drilling the Khuff gas reservoirs. If abnormal JILH pressure could be reliably predicted, 80% of the Khuff gas wells could be drilled with a "Slim Hole" casing design resulting in substantial reductions in overall well costs. This paper presents a recent pilot study for predicting abnormal pressure in the JILH in the central area of the Ghawar field, Saudi Arabia. The 3D pore pressure distribution is estimated using a state-of-the-art integrated 3D pore pressure modeling software (PP3D), which is a combination of basin modeling and data inversion techniques. All available data sets (geological, logs and drilling reports) in the area of interest were used to conduct extensive log analyses. This study identified the main cause of abnormal pressure in the JILH as fluid migration from the Sudair shale, due to formation compaction during burial. Well developed anhydrite stringers at the bottom of the base Jilh Dolomite (BJDM) blocked fluid migration to the JILH from the Sudair shale. Abnormal pressure exists in areas where these anhydrite layers did not develop well. The pore pressure along well trajectories of four wells was blind tested with the predicted 3D pore pressure distribution. The average difference in pore pressure for these blind tested wells was −4.5 pcf (−0.6 ppg). Pore pressure in eight additional wells was also blind tested and good agreement between the actual and predicted pressures was found (average difference of −0.75 pcf i.e., −0.1 ppg). It was concluded that the accuracy of the model prediction would be adequate to optimize the drilling plans and casing programs in future wells.
Sanding problems are often observed in fields after a period of relatively smooth operation. These occurrences usually coincide with an increase in depletion, water cut, or changes in the artificial lift mechanism used to produce the hydrocarbon. Sanding is detrimental to optimum field development and therefore, information about the possible advent and extent of sanding will be helpful in planning for completions and facilities. The study presented in this paper characterizes the geomechanic behavior of a field in which sanding problems are expected after depletion, increase in water cut, and installation of ESPs to optimize production. To accomplish this task, a 3D full field model was created. First, several 1D Mechanical Earth Models (MEMs) were developed. These 1D MEMs were calibrated using drilling data, laboratory measurements, well tests and other field measurements. The calibrated rock mechanical properties from the 1D MEMs were distributed in the 3D model using Gaussian sequential simulation technique. The populated 3D model was then used to perform a coupled geomechanical simulation to evaluate the changes in stress with time and production. The rock mechanical properties and stresses needed to perform sanding analysis were sampled along the well trajectories from the 3D model. Sand production prediction analysis was subsequently undertaken using a field proven sanding prediction model that accounts for scale effects associated with different perforation size and sand grain diameter, and plasticity effects that modify the strength behavior of sands surrounding open holes and perforations during drawdown and production. The sanding tendency predicted from sanding analysis was corroborated with field observations. This was also used to calibrate the 3D model and formulate a completion strategy to minimize sand production for the life of the field. The completion strategy optimizes the production using ESPs while minimizing sand production. Introduction Sand production is a major problem in many oil and gas reservoirs worldwide. It can drastically reduce production rates, damage downhole/subsea equipment and surface facilities, thus increasing the risk of well failure. The problems are often observed in fields after a period of relatively smooth operation. These occurrences usually coincide with an increase in depletion, water cut, or changes in the artificial lift mechanism used to produce the hydrocarbon. The potential of sand production is dependent on various factors including in-situ stresses, pore pressure, formation properties, depletion, water-cut etc. If the strength of reservoir rock is low, it will require sand control. On the other hand, high strength rock is not expected to sand and therefore, does not require sand control. Reservoirs with rock strength from moderate to intermediate will benefit most from a sanding prediction study. The completion and operational decisions to prevent or control sanding need to be taken on a well to well basis by considering the individual characteristics of each well. The well characteristics include inclination and orientation in the in-situ stress field and formation strength.
As a part of field development campaign to produce heavy-oil from a shallow sandstone reservoir, among vertical wells, drilling of horizontal wells was considered as an option. However, due to the weak and unconsolidated nature of the reservoir sand, the stability of horizontal wellbore during drilling was considered a major unknown. The stability of rock around the wellbore during drilling is function of several factors including rock strength, in situ stresses, pore pressure and drilling parameters. Integration of a wide variety of data into a geomechanical analysis is required for wellbore stability predictions.A comprehensive geomechanical study of the unconsolidated sandstone reservoir was conducted by incorporating data from six vertical offset wells in order to constrain the contemporary state of stress and rock strength profiles as a function of depth. The aim of the study was to evaluate the risk of hole stability during drilling, recommend a mud weight for drilling upcoming horizontal wells and to suggest azimuths along which horizontal wellbores will be more stable during drilling and production.To closely simulate the actual stress state and rock deformation around the wellbore during drilling, a 3D Finite Elementbased wellbore model was built. The analysis was performed for a range of mud weights to analyze the sensitivity of wellbore stability to mud weight variations. Based on the study, a mud weight was recommended to drill the planned horizontal wells. In addition, the analysis implied that for the observed stress state in the study field, horizontal wells oriented sub-parallel to the minimum horizontal in situ stress would be more stable during drilling and production compared to those oriented sub-parallel to the maximum horizontal in situ stress.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.