Advancements in numerical well testing packages in interpreting pressure transient behavior of complex well geometries and reservoir structures have lead to an improved understanding of the multi-scale heterogeneity encountered in dual-porosity dual-permeability (DPDP) reservoirs. This paper demonstrates the power of numerical well testing models in handling conceptual cases of increasing complexity in dual-porosity dual-permeability (DPDP) reservoirs where a high permeability matrix system interact with super-k intervals, fractures, and faults systems with different levels of complexity. Numerical well test models are built using data from multiple scales and sources (image logs, flowmeter responses (PLTs), petrophysical logs (FALs), and seismic attributes) to match pressure transient responses of wells completed in dual-porosity dual-permeability reservoirs. Six generalized conceptual cases are presented in this paper; a vertical power water injector that initiated induced fractures due to injection above fracture pressure, a vertical well near an area of intersecting faults, a 40-degree deviated well intersecting diffuse fracture network, a deviated well near a conductive fracture corridor, a horizontal well intersecting a finite conductivity fracture, and a horizontal well intersecting an infinite conductivity fracture. An integrated approach was used to match the pressure responses in all cases. Experience shows that the most representative well test solution comes from a thorough integration of well-test data with all available static and dynamic data (e.g. image logs, flowmeter responses (PLTs), geophysical, and petro-physical data). In addition, inclusion of pressure transient responses of offset wells in the area understudy as part of the analysis is crucial in choosing the most representative well test model. In summary, this paper provides guidance and best practice to reservoir engineers in building numerical well test models to analyze fracture and matrix responses in dual-porosity dual-permeability (DPDP) reservoirs. Conceptual cases emphasize integration of multiple sources of static and dynamic data to model different well responses.

This paper presents the results of pressure transient analysis carried out in several wells in a carbonate reservoir sequence, which has facilitated the assessment of the degree of vertical communication across various flow units on a larger reservoir scale. This enables the reduction of uncertainties in the full field reservoir simulation model, which is a key for the successful reservoir development plans. One of the major uncertainties that impact any reservoir development of relatively thin flow units, in a stratified carbonate reservoir, is the incomplete knowledge of the vertical inter-reservoir communication. This includes characterisation of vertical and lateral flow barriers such as, horizontal baffles, compartmentalisation and sealing faults. A well testing campaign was implemented in the high uncertainty areas of the reservoir to assess the degree of communication. The paper discusses a few examples of the well tests to demonstrate the approach utilized for the assessment. The testing procedure for the dynamic data acquisition in this study included extended flowing periods followed by extended pressure build-up periods that were analyzed by analytical and numerical modelling methods. The results indicated that there is vertical communication in the vicinity of some wells due to the discontinuity of the natural barriers, whereas for some other wells in the field a complete isolation has been exhibited within their drainage area. Introduction This study was conducted on the most mature field on production in Saudi Arabia. The main producing interval is a thick carbonate reservoir sequence with varying properties of excellent to fair limestone and dolomite. The best rock properties are located towards the upper zones of the main carbonate sequence with flow capacity values (kh) ranging from 100,000 md.ft to more than 1 million md.ft. The vertical wells in swept areas have been sidetracked and placed at the very top of the reservoir to produce the remaining attic oil column. The top 30 ft attic oil has relatively lower reservoir quality1, compared to the main producing interval, with porosities ranging from 15% to 20% and flow capacity values ranging from 1000 md.ft to 5000 md.ft. Figure-1 shows the location of the attic oil interval compared to the main reservoir carbonate sequence. Some recent saturation logs run in wells close to flank injectors have suggested original oil saturation values in this upper most zone leaving a very promising target for attic oil production. This study is focused on this attic oil interval, and it aimed to assess the degree of communication with the main carbonate sequence below in the areas of high uncertainty. A successful outcome in minimizing the geological uncertainties of the vertical flow barriers across the field will contribute for a better well placement strategy for the attic oil zone and guide the pressure support strategy of this interval. Geology of Attic Oil Zone The attic oil interval is divided into two main sections (Figure-2), the upper and the lower lobes1. The upper lobe is a 5 ft to 10 ft thick limestone separated from the lower lobe by a thin impervious anhydrite layer of 1 ft to 5 ft thick. The lower lobe is a 15 ft limestone with low dolomite content. The basal layer of the lower lobe is often a very tight dolomite which might act as vertical flow barrier in some areas. As the anhydrite and dolomite layers could act as vertical flow barriers, its distribution across the field is crucial for developing the untapped reserves in the attic oil zone.

This paper presents a comprehensive pressure transient analyses (PTA) based dynamic reservoir characterization of a mature giant carbonate oil field. An important part of an integrated reservoir study is to reconcile differences between the static and dynamic models. In this study, a large number of well tests were analyzed and integrated with other field data. The current study highlights the paramount importance of PTA for a refined reservoir description, including permeability modeling and characterizing intersecting or nonintersecting conductive fractures and faults across the field. This well tests data review has also broadened the field dynamics understanding along with the strengths of the synergic multidisciplinary approach as the PTA data is integrated with other reservoir characterization data types. The subject field is composed of two naturally fractured reservoirs separated by a thick non-permeable zone. The Upper reservoir is prolific, while the Lower reservoir is relatively tight and highly fractured. Early pressure data confirms communication between the two reservoirs through several large scale fractures crossing the thick non-permeable zone. For the purpose of this study, the field has been divided into several areas, with representative well data from both the Upper and Lower reservoirs. Pressure buildups from multi-well groups, generally conducted as single-phase (before water breakthrough), were analyzed by advanced analytical and/or numerical models. The selected interpretation model was dependent on the reservoir complexities diagnosed from the derivative plots. The analyses provided valuable well parameters, such as flow capacities and productivity indices, which are critical as input for permeability modeling and simulation model history-matching. Subsequently, equally important is the detection of reservoir description events that can be observed from the PTA response, e.g., areas of inter-reservoir communication, super permeability zones or quantification of fracture characteristic parameters. The presented case study includes well examples of the major observed field reservoir features.

Water injection into oil reservoirs is widely used practice to support oil production by maintaining the reservoir pressure within a desirable range to avoid a decline in reservoir pressure. Frequent monitoring of the water injectivity in the injection wells are very crucial to ensure meeting injection targets for an optimum level of reservoir management. Therefore, transient tests on water injection wells are an essential component in the data acquisition program of oil fields as these reveal important dynamic information about the wellbore condition and the reservoir characteristics. Usually, surface water is used for injection where the contrast in temperatures between the injected water (relatively colder) and the oil reservoir which is deep in the ground (hotter) creates a progressive colder-water bank inside the reservoir. Such a colder bank would have an effect on the injectivity of the well. Using traditional models without considering the thermal effect might result in underestimating or overestimating both reservoir flow capacity and skin damage. In this research, we will use a thermal model to study the pressure behavior during injection and falloff periods and observe the development of a colder-water front in which its size inside the reservoir will be investigated varying different parameters, such as duration of injection history, injection rate, and reservoir permeability. In addition, we will demonstrate the impact of the cold-water front on the injectivity.

A solid understanding of challenging reservoir complexities such as, naturally fractured "super-k" zones, layered systems, or, wellbore conditions such as, thermally induced mobility changes in the near wellbore region due to injection and uneven formation damage distribution across the wellbore, is essential for a successful development of carbonate reservoirs. These type of complexities play a major role for both reservoir fluid flow and well productivity. An efficient and holistic approach encompassing multiple data sources like image logs, production analysis logs, and pressure transient analysis (PTA) outcomes is of paramount importance in the characterization process of carbonate systems. In this paper illustrative examples showing different complexities, at reservoir level and also at well level, are presented in a systematic way to show the importance of pressure transient analysis (PTA) insights as a building block in the description process of these challenging reservoir features. Reconciling the differences between the static and dynamic data sources in each case was a crucial step to minimize the uncertainties encountered and to significantly broaden the dynamic understanding of these complex reservoir heterogeneities under a synergistic approach. Pressure buildups and falloffs data from multi-well groups, were incorporated and analyzed by advanced numerical models. The selected interpretation models were dependent on the reservoir and wellbore condition diagnosed from the pressure derivative plots. The analyses of wireline and large, real-time Intelligent Field data have provided key dynamic well parameters, such as permeability-thickness product (kh), productivity index and anisotropy ratio (kv/kh), that were critical input parameters in the characterization process of these complex reservoir systems.