Complex Stimulation Approach to Low-Temperature Carbonate Formation Revitalizes Bahrain Brownfield

Carbonate formations often require stimulation treatments to be developed economically. Sometimes, proppant fracturing yields better results than acid stimulation. Carbonates are seldom stimulated with large-mesh-size proppants due to admittance issues caused by fissures and high Young’s modulus and narrow fracture width. The Magwa formation of Bahrain’s Awali brownfield is a rare case in which large treatments using 12/20-mesh proppant were successful after the more than 50 years of field development. To achieve success, a complex approach was required during preparation and execution of the hydraulic fracturing campaign. During the first phase, the main challenges that restricted achieving full production potential in previous stimulation attempts (both acid and proppant fracturing) were identified. Fines migration and shale instability were addressed during advanced core testing. Tests for embedment were conducted, and a full suite of logs was obtained to improve geomechanical modeling. In addition, a target was set to maximize fracture propped length to address the need for maximum reservoir contact in the tight Magwa reservoir and to maximize fracture width and conductivity. Sufficient fracture width in the shallow oil formation was required to withstand embedment. Sufficient conductivity was required to clean out the fracture under low-temperature conditions (124°F) and to minimize drawdown along the fracture considering the relatively low energy of the formation (pore pressure less than 1,000 psi). Understanding the fracture dimensions was critical to optimize the design. Independent measurement using high-resolution temperature logging and advanced sonic anisotropy measurements after fracturing helped to quantify fracture height. As a result of the applied comprehensive workflow, 18 wells were successfully stimulated, including three horizontal wellbores with multistage fracturing - achieving effective fracture half-lengths of 450-to 500-ft. Oil production from the wells exceeded expectations and more than doubled the results of all the previous attempts. Production decline rates were also less pronounced due to achieved fracture length and the ability to produce more reservoir compartments. The increase in oil recovery is due to the more uniform drainage systems enabled by the conductive fractures. The application of new and advanced techniques taken from several disciplines enabled successful propped fracture stimulation of a fractured carbonate formation. Extensive laboratory research and independent geometry measurements yielded significant fracture optimization and resulted in a step-change in well productivity. The techniques and lessons learned will be of benefit to engineers dealing with shallow carbonate reservoirs around the world.

Wellbore Stability Beyond Mud Weight

Drilling oil and gas wells with stable and good quality wellbores is essential to minimize drilling difficulties, acquire reliable openhole logs data, run completions and ensure well integrity during stimulation. Stress-induced compressive rock failure leading to enlarged wellbore is a common form of wellbore instability especially in tectonic stress regime. For a particular well trajectory, wellbore stability is generally considered a result of an interplay between drilling mud density (i.e., mud weight) and subsurface geomechanical parameters including in-situ earth stresses, formation pore pressure and rock strength properties. While role of mud system and chemistry can also be important for water sensitive formations, mud weight is always a fundamental component of wellbore stability analysis. Hence, when a wellbore is unstable (over-gauge), it is believed that effective mud support was insufficient to counter stress concentration around wellbore wall. Therefore, increasing mud weight based on model validation and calibration using offset wells data is a common approach to keep wellbore stable. However, a limited number of research articles show that wellbore stability is a more complex phenomenon affected not only by geomechanics but also strongly influenced by downhole forces exerted by drillstring vibrations and high mud flow rates. Authors of this paper also observed that some wells drilled with higher mud weight exhibit more unstable wellbore in comparison with offset wells which contradicts the conventional approach of linking wellbore stability to stresses and rock strength properties alone. Therefore, the objective of this paper is to analyze wellbore stability considering both geomechanical and drilling parameters to explain observed anomalous wellbore enlargements in two vertical wells drilled in the same field and reservoir. The analysis showed that the well drilled with 18% higher mud weight compared with its offset well and yet showing more unstable wellbore was, in fact, drilled with more aggressive drilling parameters. The aggressive drilling parameters induce additional mechanical disturbance to the wellbore wall causing more severe wellbore enlargements. We devised a new approach of wellbore stability management using two-pronged strategy. It focuses on designing an optimum weight design using geomechanics to address stress-induced wellbore failure together with specifying safe limits of drilling parameters to minimize wellbore damage due to excessive downhole drillstring vibrations. The findings helped achieve more stable wellbore in subsequent wells with hole condition meeting logging and completion requirements as well as avoiding drilling problems.

Identification of Geo – Hazard Using Pore Pressure Analysis in ‘MAC’ Field, Niger Delta

Identification of geo-hazard zones using pore pressure analysis in ‘MAC’ field was carried out in this research. Suite of wireline logs from four wells and RFT pressure data from two wells were utilized. Lithologic identification was done using gamma ray log. Resistivity log was used to delineate hydrocarbon and non-hydrocarbon formations. Well log correlation helps to see the lateral continuity of the sands. Pore pressure prediction was done using integrated approaches. The general lithology identified is alternation of sand and shale units. The stratigraphy is typical of Agbada Formation. Three reservoirs delineated were laterally correlated. Crossplot of Vp against density (Rho) colour coded with depth revealed that disequilibrium compaction is the main overpressure generating mechanism in the field. Prediction of overpressure by normal compaction trend was generated and plot of interval transit time against depth show that there is normal compaction from 250m to about 1700 m on MAC-01, but at a depth of about 1800m, there was abnormal pressure build up that shows the onset of overpressure. A relatively normal compaction was observed on MAC-02 until a depth of about 2100m where overpressure was suspected. The prediction of formation pore pressure using Eaton’s and Bower’s method to determine the better of the two methods to adopt for pore pressure prediction shows that the pore pressure prediction using Eaton’s method gave a better result similar to the acquired pressure in the field. Hence Eaton’s method appears to be better suited for formation pore pressure estimation in ‘MAC’ field. The validation of the pore pressure analysis results with available acquired pressure data affirmed the confidence in the interpreted results for this study.

Integrated Mechanical Earth Modeling for Predicting Sand Production: A Case Study

Summary Sand production is a serious problem in oil and gas wells, and one of the main concerns of production engineers. This problem can damage downhole equipment and surface production facilities. This study presents a sand production case and quantifies sanding risks for an oil field in Iraq. The study applies an integrated workflow of constructing 1D Mechanical Earth Modeling (MEM) and predicting the sand production with multiple criteria such as shear failure during drilling, B index, and critical bottomhole pressure (CBHP) or critical drawdown pressure (CDDP). Wireline log data were used to estimate the mechanical properties of the formations in the field. The predicted sand production propensity was validated based on the sand production history in the field. The interpretation results of some wells anticipated in this study showed that when a shear failure occurs during drilling, the B index is around 2 × 104 MPa or less and the CBHP is equal to the formation pore pressure. For this case, sand control shall be carried out in the initial stage of production. On the other hand, when the shear failure does not exist, the B index is always greater than 2 × 104 MPa, and the CBHP is mostly less than the formation pore pressure. In this case, implementing sand control methods could be postponed as the reservoir pressure undergoes depletion. However, for the anticipated field, sand control is recommended to be carried out in the initial stage of well production even when the CBHP is less than the formation pore pressure since sanding will be inevitable when the reservoir pressure depletes to values close to the initial reservoir pressure. The tentative evaluation of the stress regime showed that a normal fault could be the stress regime for the formations. For a normal fault stress regime, the study explained that when the reservoir permeability is isotropic, an openhole vertical wellbore has less propensity for sand production than a horizontal wellbore. Moreover, when the wellbore azimuth is in the direction of the minimum horizontal stress, the CBHP will be lower than in any other azimuth, and sanding will take place at higher wellbore inclination angles. For the anticipated field, because of the casedhole well completion and the anisotropic reservoir permeability, a horizontal well drilled in the direction of minimum horizontal stress with oriented perforation in the direction of maximum horizontal stress is an alternative method for controlling sand production.

Calculation of Average Reservoir Pore Pressure Based on Surface Displacement Using Image-To-Image Convolutional Neural Network Model

The average pore pressure during oil formation is an important parameter for measuring the energy required for the oil formation and the capacity of injection–production wells. In past studies, the average pore pressure has been derived mainly from pressure build-up test results. However, such tests are expensive and time-consuming. The surface displacement of an oilfield is the result of change in the formation pore pressure, but no method is available for calculating the formation pore pressure based on the surface displacement. Therefore, in this study, the vertical displacement of the Earth’s surface was used to calculate changes in reservoir pore pressure. We employed marker-stakes to measure ground displacement. We used an improved image-to-image convolutional neural network (CNN) that does not include pooling layers or full-connection layers and uses a new loss function. We used the forward evolution method to produce training samples with labels. The CNN completed self-training using these samples. Then, machine learning was used to invert the surface vertical displacement to change the pore pressure in the oil reservoir. The method was tested in a block of the Sazhong X development zone in the Daqing Oilfield in China. The results showed that the variation in the formation pore pressure was 83.12%, in accordance with the results of 20 groups of pressure build-up tests within the range of the marker-stake measurements. Thus, the proposed method is less expensive, and faster than existing methods.

Significant Performance Improvement with MPD in HPHT Narrow Drilling Window Campaign in the North Sea

Significant depletion in reservoir pressure, huge uncertainties in pore and fracture pressure, high overburden pressure on top of reservoir, Narrow Mud Weight Window (NMWW) and Partial/Total losses whilst entering the reservoir made these HPHT (High Pressure High Temperature) wells conventionally un-drillable. Due to these substantial challenges these wells were considered not only costly but also carry a high probability of failure to reach well TD (Total Depth). MPD (Managed Pressure Drilling) is a safer and more effective drilling technique as compared to conventional drilling, especially in wells with NMWW and downhole hazards. The precise determination and dynamic downhole pressure management was imperative to complete these wells without well control incidents. The Constant Bottom Hole Pressure (CBHP) variant in combination of automated MPD system was deployed with a mud weight statically underbalanced while dynamically managed above formation pore pressure to minimize the overbalance across the open hole. MPD enabled the operator to efficiently navigate Equivalent Circulation Density (ECD) through the pore and fracture pressure window, allowed significant improvements throughout the entire campaign. This paper discusses the challenges faced during the last three wells drilled in the campaign which includes equipment issues, commissioning delays, losses whilst drilling, Managed Pressure Cementing (MPC), 7" drill-in-liner and plugged/blocked lines due to weather and mud conditions. The paper describes HPHT infill drilling experience, specific techniques, practices as well as lessons learned from each well during the campaign were implemented to address challenges and to improve performance. The MPD system commissioning was optimized by repositioning the lines which saved significant critical rig time. The blowdown points were added on the lines that were not operational continuously therefore a procedure was developed for flushing to avoid plugging. Optimized drilling strategy was also developed where MW was further reduced to avoid losses as observed in previous wells and CBHP was maintained by manipulating Surface Back Pressure (SBP) from surface. This paper also discusses continuous improvements /upgrades in MPD operating software which assisted the operator in accurate monitoring of flow, SBP and BH-ECD to save significant rig cost in terms of invisible Non-Productive Time (NPT). MPD is a drilling enabler and performance enhancer which saved 80 days of Authorization for Expenditure (AFE) on this challenging HPHT campaign.

FORMATION PRESSURE ESTIMATION IN ULTRA-LOW PERMEABLE RESERVOIRS EMPLOYING FORMATION RATE ANALYSIS (FRA) AND ARTIFICIAL INTELLIGENCE CONTROLLED TOOLS

The necessity of knowing formation pressure is crucial to classifying pressure regimes for better understanding in well planning and to de-risk potential abnormal pressure conditions before any future field development wells are drilled, consequently minimizing operational cost. Wireline formation pressure testing has been a useful and reliable technology, that has evolved to confront the challenge of ultra-low permeable reservoir conditions by innovating and improving pump capability, accuracy in pressure measurements, automated control and the implantation of Formation Rate Analysis (FRA) intertwined with an Artificial Intelligent tool. In any pressure testing, the key factor is to be able to withdraw volume from the formation to generate a disturbance on formation pore pressure that a pressure gauge can measure. In the past this has been a difficult task in ultra-low permeable zones. The new generation of wireline tools are capable of withdrawing volume from ultra-low permeable reservoirs, with mobilities lower than 0.01mD/cP. This has been made possible by utilizing control of the pump speed down to 0.0003cc/s which then gives the operator the ability to test ultra-tight formations without the need for inflatable packers. By pulling down the pressure at an extremely low rate and using Artificial Intelligence to control the rate by knowing the formation rate, a proportional amount of volume can be extracted without calling it a tight test. During the operation by observing the rate, and making sure the pump is not oscillating, which indicates the formation rate is lower than the lowest rate the pump can withdraw, the test can be validated for formation flow and the pressure transient of the build – up can be analysed to confirm that at least spherical flow is observed. Once reservoir communication has been confirmed and by analysing drawdown and build-up pressure versus volume withdrawn and implementing the FRA equation, the reservoir pressure can be back calculated by considering isothermal compressibility and FRA slope. This paper highlights the best technical approach to quality check and quality control these tests, showing examples of various wells, where the technique has been used to predict a formation pressure, which can be used for further use for field development, drilling optimisation and production profiles. These pressures would never have been possible using static rates and volume.

Abnormal Pressure Distribution of Tertiary age formations in Middle & South Iraqi Oil Fields

Prediction of formation pore pressure gradient is a very important factor in designingdrilling well program and it help to avoid many problems during drilling operations such as lostcirculation, kick, blowout and other problems.In this study, abnormal formation pressure is classified into two types; abnormal highpressure (HP) and abnormal low pressure (LP), therefore any pressure that is either above orbelow the hydrostatic pressure is referred to as an abnormal formation pressure.This study concerns with abnormal formation pressure distribution and their effect ondrilling operations in middle & south Iraqi oil fields. Abnormal formation pressure maps aredrawn depending upon drilling evidence and problems.Three formations are considered as abnormal formations in the region of study, theseformations geologically existed in Tertiary age and they from shallower to deeper are: LowerFars, Dammam and Umm Er Radhuma, Formations. The maps of this study referred to eitherhigh formations pressure such as (Lower Fars and Umm Er Radhuma) or the low formationspressure such as (Dammam) in middle and south of Iraq. Finally these maps also suggested andshowed the area, where no field is drill until now, which may behave as high, low and normalformation pressure for every formation understudy.