Achieving Productivity and Clean Inflow from an Unconventional Reservoir in North Kuwait

2022 ◽  
Author(s):  
Zamzam Mohammed Ahmed ◽  
Abrar Mohammed Salem ◽  
Liu Pei Wu ◽  
Benjamin Mowad
Keyword(s):  
Particulate Material ◽  
Primary Objective ◽  
Carbonate Reservoir ◽  
Hydraulic Fractures ◽  
Full Field ◽  
Fully Integrated ◽  
New Era ◽  
Field Development ◽  
Shale Reservoirs ◽  
Rock Mechanical Properties

Abstract Jurassic Kerogen shale/carbonate reservoir in North Kuwait provides the same challenges as North American shales in addition to ones not yet comparable to any other analogue reservoir globally. It is the Kerogen's resource density; however, that makes this play so attractive. Like ‘conventional’ unconventional in the US and Canada this kerogen is believed to be a source rock and is on the order of micro-to nano-Darcy permeability. As such, industry learnings show that likely long horizontal laterals with multiple hydraulic fractures will be necessary to make commercial wells. Following this premise, the immediate objective is to establish clean inflow into wellbore as the previous attempts to appraise failed due to "creep" of particulate material and formation flowing into the wellbore. Achieving this milestone will confirm that this formation is capable of solids free inflow and will open a new era in unconventional in Kuwait. Planning for success, the secondary objective is to then upscale to full field development. The main uncertainties lie in both producibility and ‘frac-ability’, and certainly, these challenges are not trivial. A fully integrated testing program was applied to both better understand the rock mechanical properties and to land on an effective frac design. Scratch, unconfined stress, proppant embedment and fluid compatibility tests were conducted on full core samples for geo-mechanics to prepare a suite of strength measurements ahead of frac design and to custom-design the fracture treatment and "controlled" flowback programs to establish inflow from Kerogen without "creep". Unlike developed shale reservoirs, the Jurassic Kerogen tends to become unconsolidated when treated. The pre-frac geomechanics tests will be outlined in this paper with the primary objective of finding the most competent reservoir unit to select the limited perforation interval to frac through so that formation competency can be maintained. Previous attempts failed to maintain a competent rock matrix even only after pumping data-fracs. Acidizing treatments also turn the treated rock volume into sludgy material with no in-situ stability nor ability to deliver "clean inflow". A propped fracturing treatment with resin-coated bauxite was successfully placed in December 2019 in a vertical appraisal well perforated over 6 ft at 12 spf shot density. "Controlled" flowback carried out in January 2020 achieved the strategically critical "clean inflow" with reservoir fluids established to surface. Special proppant technologies provided by an industry leading manufacturer overcame the embedment effects and to control solids flowback. A properly designed choke schedule to balance unloading with a delicate enough drawdown to avoid formation failure was executed. Local oilfields relied on the vast reserves and produced easily from carbonate reservoirs that required only perforating or acid squeezes to easily meet or exceed high production expectations. This unconventional undertaking in Kuwait presents a real challenge as it is a complete departure from the ways of working yet it points towards a very high upside potential should the appraisal campaign can be completed effectively.

First Successful Pilot Testing of Unconventional Reservoir in North Kuwait from Scratch to Productivity

2021 ◽  
Author(s):  
Zamzam Mohammed Ahmed ◽  
Abrar Mohammed Salem ◽  
Jose Ramon ◽  
Liu Pei Wu ◽  
Benjamin Mowad
Keyword(s):  
Hydraulic Fracturing ◽  
Particulate Material ◽  
Carbonate Reservoir ◽  
Hydraulic Fractures ◽  
Single Fracture ◽  
Gas Field ◽  
Field Development ◽  
Creep Effect ◽  
Fracture Closure ◽  
Lab Test

Abstract Jurassic's kerogen shale-carbonate reservoir in North Kuwait is categorized as a source rock exhibiting micro- to Nano Darcy permeability and is Kuwait Oil Company's focus in recent years. Although the challenges are significant (formation creep, fracturing initiation, etc.), the efforts toward producing from unconventional reservoirs and applying experience from both USA and Canada in this field are ongoing. As a step toward development, the gas field development group selected a vertical pilot well to measure the inflow of hydrocarbon from a single fracture while minimizing formation creep (flowing of particulate material and formation into the wellbore that blocks the production). This step was required prior to drilling a long horizontal lateral wells and completing it with multiple hydraulic fractures to confirm commercial production. A comprehensive design process was executed with the full integration of operator and service company competencies to achieve the three main objectives: First, characterize the kerogen rock mechanics which allows selection of the most competent kerogen beds to prevent collapse of the hole during fracturing (creep effect) by conducting scratch, unconfined stress, proppant embedment, and fluid compatibility tests. Then, prepare a suit of strength measurements on full core samples to help in fracturing design and minimize creep effect. The second objective was to design and implement a robust proppant fracturing program that avoids the kerogen concerns after selecting the most competent reservoir unit and suitable proppant type. Third, perform controlled flowback to unload the well and attempt to establish clean inflow unlike previous attempts that failed to either suitably stimulate or prevent solids production (deliver clean inflow). After analyzing the lab test results, choosing the optimal fracturing design, and preparing the vertical well for proppant hydraulic fracturing, the treatment was performed. In December 2019, the hydraulic fracturing treatment with resin-coated bauxite proppant was successfully pumped through 6 ft of perforation interval and followed by a controlled flowback. Resin-coated bauxite proppant was specifically selected to overcome the creep and embedment effects during the fracture closure and flowback. Moreover, a properly designed choke schedule was implemented to balance unloading with a delicate enough drawdown to avoid formation failure. This paper discusses in detail the lab testing, evolution of fracturing design, treatment analysis, and the robust workflow that led to successfully achieving all main objectives, paving the way for long horizontal lateral wells. This unconventional undertaking in Kuwait presents a real challenge. It is a departure from traditional methods, yet it points toward a high upside potential should the appraisal campaign be completed effectively.

Implications of accurate geomechanical modelling and systematic core testing for sanding evaluation and sand control decisions – a case study from Perth Basin

2020 ◽  
Vol 60 (1) ◽  
pp. 267
Author(s):  
Sadegh Asadi ◽  
Abbas Khaksar ◽  
Mark Fabian ◽  
Roger Xiang ◽  
David N. Dewhurst ◽  
...  
Keyword(s):  
Management Strategies ◽  
Mechanical Tests ◽  
Well Test ◽  
Sand Production ◽  
Gas Field ◽  
Stress Regime ◽  
Full Field ◽  
Field Development ◽  
Sand Control ◽  
Rock Mechanical Properties

Accurate knowledge of in-situ stresses and rock mechanical properties are required for a reliable sanding risk evaluation. This paper shows an example, from the Waitsia Gas Field in the northern Perth Basin, where a robust well centric geomechanical model is calibrated with field data and laboratory rock mechanical tests. The analysis revealed subtle variations from the regional stress regime for the target reservoir with significant implications for sanding tendency and sand management strategies. An initial evaluation using a non-calibrated stress model indicated low sanding risks under both initial and depleted pressure conditions. However, the revised sanding evaluation calibrated with well test observations indicated considerable sanding risk after 500 psi of pressure depletion. The sanding rate is expected to increase with further depletion, requiring well intervention for existing producers and active sand control for newly drilled wells that are cased and perforated. This analysis indicated negligible field life sanding risk for vertical and low-angle wells if completed open hole. The results are used for sand management in existing wells and completion decisions for future wells. A combination of passive surface handling and downhole sand control methods are considered on a well-by-well basis. Existing producers are currently monitored for sand production using acoustic detectors. For full field development, sand catchers will also be installed as required to ensure sand production is quantified and managed.

Dynamic Modeling Workflow for an Unconventional Biogenic Gas Reservoir with Multistage Hydraulic Fracture. A Case Study of Miocene Gachsaran Formation, Abu Dhabi, United Arab Emirates

2021 ◽  
Author(s):  
Abdelghani Gueddoud ◽  
Ahmed Al Hanaee ◽  
Riaz Khan ◽  
Atef Abdelaal ◽  
Redy Kurniawan ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Development Plan ◽  
Unconventional Reservoirs ◽  
Hydraulic Fractures ◽  
Flow Mechanism ◽  
Gas Reservoir ◽  
Full Field ◽  
Gas Concentration ◽  
Biogenic Gas ◽  
Field Development

Abstract The Miocene Gachsaran Formation across Onshore Abu Dhabi and Dubai possesses high potential of generating shallow biogenic gas. A dynamic model and field development plan generated based on a detail G&G analysis to understand and evaluate its capability as promising gas resources. Specific approaches and workflow generated for volumetric and dynamic reservoir model capable of defining the most viable development strategy of the field from both an economic and technical standpoint. The proposed workflow adapts also the development plan from single pad-scale to full field development plan. A fine-grid field-scale with more than hundreds of Pads covering the sweet spot area of three thousands of square kilometers including structure, reservoir properties built based on existing vertical wells, newly drilled horizontal wells and seismic interpretation. In this paper, a robust workflow for big and complex unconventional biogenic gas reservoir modeling and simulation technique have been developed with hydraulic fracture and stimulated area created through LGR. Independent workflows generated for the adsorbed gas in place calculation, desorption flow mechanism, and Pads field development plan. An accuracy on in place calculation, desorption flow mechanism and Pseudo steady state flow through direct and indirect total gas concentration measured using (1) Pressurize core and sorption isotherm capacity experiment, (2) Langmuir /BET function and Vmax scaling curves for each grid cells, and (3) Gas concentration versus TOC relationship. Field development plan for unconventional shallow biogenic gas reservoirs is possible only if a communication network created through hydraulic fractures connects a huge reservoir area to the wellbore effectively. A complete workflow presented for modeling and simulation of unconventional reservoirs, which in-corporates the characterization of hydraulic fracture and their interaction with reservoir matrix. Dual porosity model has been constructed with accurate in place calculation through scaling the Langmuir function and calculation Vmax for each grid cell of the full field model, The single Pad design approach in the development plan has exhibited great advantages in terms of improvement in the quality and flexibility of the model, reduction of working time with the same Pad model design which is adapted for the full field development plan. The proposed unconventional modeling and field development plan workflow provides an efficient and useful unconventional dynamic model construction and full field development planning under uncertainty analysis. Minimizing the uncertainty in place calculation and production forecasting for unconventional reservoirs necessitates an accurate direct and indirect data measurement of gas concentration and flow mechanism through the laboratory measurement. Field development plan for unconventional reservoirs is possible only if fracture network can be created through hydraulic fractures that connects a huge reservoir area to the wellbore effectively through pad completion.

Interpretation of Immiscible WAG Repeat Pressure-Falloff Tests

2011 ◽  
Vol 14 (06) ◽  
pp. 687-701 ◽  
Author(s):  
B.A.. A. Stenger ◽  
S.A.. A. Al-Kendi ◽  
A.F.. F. Al-Ameri ◽  
A.B.. B. Al-Katheeri
Keyword(s):  
Water Injection ◽  
Carbonate Reservoir ◽  
Mobility Control ◽  
Reservoir Properties ◽  
Injection Wells ◽  
Pressure Derivative ◽  
Full Field ◽  
Field Development ◽  
Phase Mobility ◽  
Injection Cycle

Summary This paper reviewed the interpretation of repeat pressure-falloff (PFO) tests acquired in two vertical pattern injectors operating in a carbonate reservoir undergoing full-field development. Enhanced vertical-sweep conformance through phase mobility control in the presence of strong reservoir heterogeneity was the major expected benefit from an immiscible water-alternating-gas (WAG) displacement mechanism. PFO tests were carried out during the monophasic injection phase to determine well injectivity and reservoir properties, and were subsequently acquired at the end of each 3-month injection cycle. Analytical falloff-test interpretation relied on the use of the two zone radial composite model. Multiple falloff-test interpretations indicated that the two pattern vertical injectors behaved differently even though both had been fractured. The difference in behavior was linked to different perforated intervals and reservoir properties. Gas- and water-injection rates were showing differences between both pattern injectors as a consequence. Injected gas banks had a small inner radius and were almost undetectable at the end of the subsequent water cycle. Changes in the pressure-derivative slope at the end of the subsequent water-injection cycle indicated most likely the creation of an effective mixing zone of injected gas and water in the reservoir. Numerical finite-volume simulation was required to account for potential injected-fluid segregation and the heterogeneous multilayered nature of the reservoir. Repeat saturation logs acquired in observation wells monitored the saturation distribution away from the injection wells. Fluid saturations derived from the simulation model were showing a good agreement with the analytical results in general, although the need to account for gas trapping was confirmed. Eight planned development WAG injectors were repositioned as a consequence of WAG 1 and WAG 2 pattern performance.

Maximizing Recovery from a Depleted Oil Rim Carbonate Reservoir Through an Integrated FDP Approach: Case Study Onshore Field Abu Dhabi, UAE

2021 ◽  
Author(s):  
Magdy Farouk Fathalla ◽  
Mariam Ahmed Al Hosani ◽  
Ihab Nabil Mohamed ◽  
Ahmed Mohamed Al Bairaq ◽  
Aditya Ojha ◽  
...  
Keyword(s):  
Water Injection ◽  
Primary Objective ◽  
Carbonate Reservoir ◽  
Full Field ◽  
Water Breakthrough ◽  
Artificial Lift ◽  
Reservoir Simulation Model ◽  
Oil Rim ◽  
Project Objectives ◽  
Gas Lift

Abstract This paper examines risk and rewards of co-development of giant reservoir has gas cap concurrently produce with oil rim. The study focus mainly on the subsurface aspects of developing the oil rim with gas cap and impact recoveries on both the oil rim and gas cap. The primary objective of the project was to propose options to develop oil rims and gas cap reservoir aiming to maximize the recovery while ensuring that the gas and condensate production to the network are not jeopardized and the existing facility constraints are accounted. Below are the specific project objectives for each of the reservoirs: To evaluate the heterogeneities of the reservoir using available surveillance information data.To evaluate the reservoir physics and define the depleted oil rims current Gas oil contact and Water Oil Contact using the available surveillance information and plan mitigate reservoir management plan.To propose strategies in co-development plan with increase in oil rim recovery without impact on gas cap recovery.To propose the optimum Artificial methods to extended wells life by minimize the drawn down and reduce bottom head pressure.To propose methods to reduce the well head pressure to reduce back pressure on the wells. The methodology adopted in this study is based on the existing full field compositional reservoir simulation model for proposing different strategical co-development scenario: Auto gas lift Pilot implementation phase.Reactivate using Auto gas lift all the in-active wells.Propose the optimum wells drilling and completion design, like MRC, ERD and using ICV to control water and gas breakthrough.Proposing different field oil production plateauPropose different water injection scheme The study preliminary findings that extended reach drilling (ERD) wells were proposed, The ability to control gas and water breakthrough along the production section will be handled very well by deploying the advanced flow control valves, reactivation of existing Oil rim wells with Artificial lift increases Oil Rim recovery factor, and optimize offtake of gas cap and oil rim is crucial for increase the recovery factories of oil Rim and gas cap.

Integrated Subsurface to Surface Modeling to Assess Reservoir Uncertainty Quantification to A Carbonate Reservoir

2020 ◽  
Author(s):  
A. Chaterine
Keyword(s):  
Uncertainty Quantification ◽  
Gas Production ◽  
Carbonate Reservoir ◽  
Production Volume ◽  
Production Forecast ◽  
Uncertainty Range ◽  
Field Development ◽  
Production Forecasting ◽  
Production Scheme ◽  
Rock Compressibility

This study accommodates subsurface uncertainties analysis and quantifies the effects on surface production volume to propose the optimal future field development. The problem of well productivity is sometimes only viewed from the surface components themselves, where in fact the subsurface component often has a significant effect on these production figures. In order to track the relationship between surface and subsurface, a model that integrates both must be created. The methods covered integrated asset modeling, probability forecasting, uncertainty quantification, sensitivity analysis, and optimization forecast. Subsurface uncertainties examined were : reservoir closure, regional segmentation, fluid contact, and SCAL properties. As the Integrated Asset Modeling is successfully conducted and a matched model is obtained for the gas-producing carbonate reservoir, highlights of the method are the following: 1) Up to ± 75% uncertainty range of reservoir parameters yields various production forecasting scenario using BHP control with the best case obtained is 335 BSCF of gas production and 254.4 MSTB of oil production, 2) SCAL properties and pseudo-faults are the most sensitive subsurface uncertainty that gives major impact to the production scheme, 3) EOS modeling and rock compressibility modeling must be evaluated seriously as those contribute significantly to condensate production and the field’s revenue, and 4) a proposed optimum production scenario for future development of the field with 151.6 BSCF gas and 414.4 MSTB oil that yields a total NPV of 218.7 MMUSD. The approach and methods implemented has been proven to result in more accurate production forecast and reduce the project cost as the effect of uncertainty reduction.

A Fast, Fully Integrated Approach to Early Field Development Resource Evaluation and Value Assessment: Madu-Anyala Project - Nigeria

2009 ◽  
Author(s):  
Innocent Okoro ◽  
Jennifer Krolow ◽  
Djuro Novakovic ◽  
Adeniyi Aladesulu ◽  
Kendall Reynolds ◽  
...  
Keyword(s):  
Integrated Approach ◽  
Value Assessment ◽  
Resource Evaluation ◽  
Fully Integrated ◽  
Field Development ◽  
Development Resource
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