injector

Complex Toe-to-Heel Flooding (CTTHF) is a short distance flooding technique developed by the authors for sandstone formations. CTTHF applied on horizontal wells and requires at least one barrier and injector hydraulic fracture, also it requires at least one method to control early water production. This paper discusses the design aspects of the CTTHF including the design of barrier fracture, injector fracture, and the produced water control methods. Technical and economical evaluation to rank different design setups is performed and presented.

Advanced commercial reservoir simulator with hydraulic fracturing module was used to simulate different CTTHF setups and reservoir conditions to set the reservoir selection criteria and proper design methodology. In this study, Toe-to-Heel Waterflooding was considered the base case. Sensitivity studies for barrier fracture and injector design has been achieved and presented. Moreover, a sensitivity studies for hydraulic fractures spacing, number of barrier fractures, batch injection scheduling and changing packer location have been performed.

When CTTHF is applied in high permeable sandstone formation, early water production is expected, except produced water control method is used. This study states the feasibility conditions for each proposed produced water control technique. Also, a methodology for candidate reservoir selection, design of barrier and injector fractures is developed and presented. There are multiple fluid systems can be used to create the barrier to seal a pre-determined zone. CTTHF is better reservoir management approach.

The novelty of the CTTHF is giving multiple options for produced water control that maximizes the produced oil and minimizes the water production. CTTHF's produced water control can make some reservoirs economic to produce.

Inter-well connectivity (IWC) is one of the most significant properties when evaluating the success of a waterflood. This connectivity has been obtained from various physics-based methods such as simulations, tracers and using heuristics and semi-analytical tools like capacitance-resistance model (CRM). Production and injection data are a key piece of information required to compute the IWC. In this study, we present a new method for estimating IWC using signal processing techniques on the wavelet transform of the injection and production rate data.

First, the injection and production rates are subjected to multiresolution analysis using the wavelet transform to determine the detail coefficients. The variance of the detail coefficients is then computed and is ready to be processed using various signal processing techniques. Signal processing techniques such as cross-correlation, time lag, Spearman correlation, and Kendal correlation are used to identify the level of relationship between the processed injection and production data in wavelet scale space. Based on the correlation coefficients, a new IWC link parameter is proposed for characterizing the IWC between well pairs. The IWC link parameters between well pairs are then plotted for visual representation.

We created several simulation models for multi-well systems, established water-flood patterns, and for randomly placed wells to establish the new IWC link parameter. The resulting injection and production rates were analyzed using the methodology above and the new IWC link parameter is established in terms of cross-correlation coefficient. We also performed several simulations for a heterogenous reservoir to compute and compare the accuracy of the new IWC link parameter. Finally, the methodology is subjected to real field waterflooding, and compared against the CRM results, which shows a good agreement. The visual representation gives new insight into whether the connectivity is being affected by the reservoir or from near wellbore events (such as changes in skin).

This study integrates signal processing techniques and waterflood IWCs. Novel use of wavelet transforms coupled with variance for processing the injection and production rate data is proposed. It must be emphasized that wavelet is used in this context for processing and not for smoothing or data compression. Ultimately, this method can be implemented as a real-time automated monitoring system. Moreover, the new IWC link parameter provides insights by identifying problematic IWC, well-completion issues, and high perm channels for taking timely operational decisions.

Managing a 47-year brownfield, offshore Sarawak, with thin remaining oil rims has been a great challenge. The dynamic oil rim movement has remained as a key subsurface uncertainty especially with the commencing of redevelopment project. A Reservoir, Well and Facilities Management (RWFM) plan was detailed out to further optimize the development decisions. This paper is a continuation from SPE-174638-MS and outlines the outcome of the RWFM plan and the results’ impact towards the development decisions, such as infill well placement and gas/water injection scheme optimization. Key decisions impact by the RWFM findings are highlighted.

One of the RWFM plans is oil rim monitoring through saturation logging to locate the current gas-oil contact (GOC) and oil-water contact (OWC). Cased-hole saturation logs were acquired at the identified observation-wells across the reservoir to map time-lapse oil rim movement and its thickness distribution. Pressure monitoring with regular static pressure gradient surveys (SGS) as well as production data, helped to understand the balance of aquifer strength between the Eastern and Western flanks. Data acquisition opportunity during infill drilling were also fully utilized to collect more solid evidences on oil rim positions, where extensive data acquisition program, including conventional open-hole log, wireline pressure test, formation pressure while drilling (FPWD) and reservoir mapping-while-drilling, were implemented.

The timely collection, analysis and assimilation of data helped the team to re-strategize the development / reservoir management plans, through the following major activities:

Re-strategizing water and gas injection plan to balance back oil rim between the Eastern and Western flanks, through deferment of drilling water injectors, optimization of water and gas injectors location and completion strategies due to stronger aquifer encroachment from east and south east.

This paper highlights the importance of data integration from geological knowledge, production history, reservoir understanding and monitoring through regular SGS and time-lapse cased-hole saturation logging, coupled with extensive data acquisition during infill drilling. By analyzing and integrating the acquired data, project team can then confidently re-strategize and successfully execute the complex mature oil-rim brownfield redevelopment.

Reservoir G-4, a depleted reservoir in field B had been producing from 1992 to 2015 with a recovery factor of 30% before the production was stopped due to low reservoir pressure. Due to the huge inplace volume. A secondary recovery screening was conducted and gas injection was identified as the most suitable solution to revive G-4 reservoir due to its low cost impact of 0.4 Mil. USD whilst managing to deliver the same results as other solutions (i.e. Water injection & Water Dumpflood).

The project had utilized existing facilities in field B including a gas compressor. The project required only minor surface modification to re-route gas into the tubing of injection well BG-03. From simulation results, a continuous injection of 5 MMscf/d will increase the reservoir pressure by 150 psia in 9 months, with incremental potential reserves of atleast 5.0 MMstb from the benefitter wells, BG-02 & as well as incoming infill wells BG-14 & BG-15. It is also envisaged that with future development of additional infill wells, the recovery factor will be increased up to 60%.

In term of gas management, field B is able to deliver additional 15 MMscf/d post petroleum operation reduction (i.e. Fuel Gas, Instrument Gas & Gas lift). With the initiation of gas injection, the project had managed to utilize and optimize 33% of additional gas production for reservoir rejuvenation purposes.

The paper provides valuable insight into the case study and lesson learned of maximizing oil recovery through gas injection with minimal cost incurred. The approach is highly recommended to maximize oil recovery especially in mature fields with similar reservoir conditions and production facilities.

Net present value (NPV) and voidage replacement ratio (VRR) are the key drivers to define an optimal reservoir development strategy that maximizes returns while maintaining reservoir health. In the subsurface context, maximizing NPV consists of optimizing the well locations. Voidage replacement ratio (VRR), which is defined as the ratio between the volume of injected fluid and the volume of produced fluid, measures the rate of change in reservoir energy. Conventionally, operators try to maintain a VRR close to one during the whole field life. Typically a single value of VRR is used as a metric to represent the whole reservoir. However, this approach does not capture the lateral variation in pressure seen in giant fields.

This paper focuses on a more suitable method for determining the VRR for each user-defined pressure region using reservoir simulation. This method is used to plan the location of future wells during the long term development plan and maximize NPV and recovery. Two scenarios of well location will be examined. The first scenario consists of optimizing well location using a single VRR metric for the whole field. The second scenario uses the VRR from each pressure region to decide on the optimum number of wells per region.

This latter approach is shown to give better results in planning well location for future field development and is consistent with the reservoir pressure distribution across the field.

An accurate evaluation of injectivity is essential to the economics of any chemical EOR process. Most commercial simulators enable non-Newtonian behaviour modelling but it is often overlooked due to inadequate grid resolution. Indeed, in cases where shearthinning fluids are injected in a reservoir, shear rates and viscosities in the vicinity of the wellbore can be poorly estimated if the spatial resolution of the well grid-blocks is too coarse. This results in biases in injectivity and economics which we discuss here in the context of foam-based displacements.

We consider continuous foam injection in models of different spatial resolutions ranging from 1 to 100 m gridblock sizes and study the behaviour of injection wells obtained on the coarser grids compared with the results from a high resolution grid. This reference grid is sufficiently refined to account for near-wellbore large velocity gradients and render injectivity accurately. In this work we propose new formulations of the well index that capture shear-thinning behaviour that the conventional Peaceman calculation fails to address.

We first demonstrate that a poor evaluation of near-wellbore velocity leads to erroneously degraded injectivity on the coarser grids when compared to the reference grid. In order to correct these errors our modified well index is applied and validated in various scenarios of foam displacement simulation with radial grids. It captures a more accurate injectivity than the conventional Peaceman calculation once steady-state regime is reached. The modified well index we propose, used under a simplified form as direct input in reservoir simulation, significantly enhances injectivity estimates without resorting to grid refinements or modifying the shear-thinning model of the injected foam. In most cases it yields results that are closer to those obtained using grid refinements than the Peaceman formula at a much more attractive computational cost. Additional work remains to complete our understanding of injectivity in more complex settings, especially in the context of foam injection when effects such as foam dry-out and destruction in the presence of oil are as important on sweep efficiency as its shear-thinning behaviour.

Our workflow successfully corrects biases in the estimation of injectivity and yields more accurate results and avoids resorting to time-consuming methods such as grid refinements and physical input data alteration. Moreover it is simple to implement in most commercial simulators and does not require using empirical criteria. However, it bears some limitations which we also discuss.

This paper discusses the re-construction of the long-term development plan for an offshore giantfield located in Abu Dhabi with the aim to mitigate the rising challenges in the maturing field. The primary objective is to understand the reservoir behavior in terms of fluid movement incorporating the learning from the vast history while correlating with the geological features.

The field has been divided into segments based on multiple factors considering the static properties such as facies distribution, diagenesis, faults, and fractures while incorporating the dynamic behaviors including pressure trends and fluid movements.

On further analysis, various trends have been identified relating these static and dynamic behaviors. The production mechanism for each of the reservoirs and the subsequent sub reservoirs were analyzed with the help of Chan plots, Hall plots and Lorentz plots which distinctly revealed trends that further helped to classify the wells into different production categories.

Using the above methodology the field has been categorized in segments and color coded to indicate areas of different ranking. The green zone indicates area of best interest which currently has strong pressure support and wells can be planned immediately. The wells in this area are expected to produce with a low risk of water and gas. The yellow zone indicates areas of caution where special wells including smart wells maybe required to sustain production. This area showed relatively lower pressure support owing the location of the water injectors and the degraded facies quality between the injectors and the producers. The red zone highlights areas which are relatively mature compared to the neighboring zones and will require new development philosophy to improve the recovery. The findings from this study were used as the basis for a reservoir simulation study using a history matched model, to plan future activities and improve the field recovery.

This study involved an in-depth analysis incorporating the latest findings with respect to the static and dynamic properties of the reservoir. This has helped to classify the reservoir based on the development needs and will play a critical role in designing the future strategies in less time.

3D model is a valuable tool in reservoir management, provided its representativeness of reservoir dynamics.Traditional History Match mainly focuses on reproducing reservoir behavior at well scale. A good match is not always representative of fluid movements in the reservoir. The proposed approach for 3D model validation combines and compares the results of integrated production analysis, in particular flow paths identification, with history matching by using streamlines technology. Streamlines speed up the comparison process especially in complex 3D models.

The workflow is based on a massive Production Data Analysis (PDA) where geological and dynamic data are integrated to identify preferential paths followed by the different fluid phases during the producing life of the field. The main result is the Fluid Path Conceptual Model (FPCM) where aquifer and injected water movements are clearly identified. Once the flooded areas are detected, streamlines are traced on the history matched model in order to easily compare the simulated connections with hard information from PDA. Actions to improve the model representativeness are suggested and integrated in an iterative tuning process.

This paper presents the results of the methodology applied on two complex fields with different injection strategies. FPCMs resulting from PDA provided a powerful boost to drive the history match and speed up the whole process. Priority was given in reproducing the identified preferential paths rather than to perfectly match well production data (which can be also affected by allocation uncertainties) by means of local unrealistic adjustments.

Streamlines were run on Intersect simulation, proving to be a fast and powerful tool for the visualization and understanding of fluid movements in the 3D Model. Since streamlines are used as visualization tool and are traced on a corner point geometry grid using fluxes provided by reservoir simulation, the reliability of the simulation output is preserved.

Once the model is representative of the real field behavior, it can be used as predictive tool in Reservoir Management to optimize the current injection strategy, promoting most efficient injectors.

Although SAGD is a very popular in-situ extraction method in Canada, this thermal process relies on huge energy and water consumption to generate the steam. Irregular growth of the steam-chamber due to heterogeneities further degrades its yield. Contact between the steam chamber and the overburden also leads to heat losses. The objective of this paper is to investigate how Foam Assisted-SAGD could mitigate these technical issues and improve the efficiency of the SAGD process. Compositional thermal reservoir simulations are used to simulate and analyze a Foam Assisted-SAGD pilot. The shear-thinning effect close to the wells is also accounted for. The simulations are run on a homogeneous model mimicking the Foster Creek project in Alberta, Canada. Several type of injection sequences have been analyzed in terms of foam formation, back-produced surfactants and cumulative Steam-Oil-Ratio. Results are compared with the original SAGD performance. In order to propagate the foaming surfactants throughout the steam chamber the injection sequence needs to be properly determined. A simple continuous Foam Assisted-SAGD injection would lead to an accumulation of surfactant between the wells due to gravity segregation, preventing the foam from acting on the upper part of the steam chamber. Furthermore surfactant production occurs after a few weeks due to the proximity of the producer and the injector. A proper injection strategy of the type SAGD/slug/SAGD/slug is found to delay the chemical breakthrough and increase the amount of surfactant retained in the reservoir while allowing the surfactant propagation throughout the steam chamber. After optimization the Foam Assisted-SAGD process appears to be technically promising.

A reservoir simulation study has been performed to assess the enhanced oil recovery benefits for a proposed pilot on Simultaneous Injection of Miscible Gas (CO₂) and Polymer (SIMGAP) in a giant carbonate reservoir (B) in Abu Dhabi. The model has been used to carry out uncertainty analysis for various input parameters and analyze their impact on pilot performance. The paper discusses the uncertainty analysis in detail.

Reservoir-B consists of B_Upper and B_Lower layers which are in full hydrodynamic equilibrium. However, in the southern and western parts of the reservoir, the B_Upper layer has permeabilities that are one to two orders of magnitude higher than the B_Lower layer. The reservoir is on plateau production under waterflooding, however, it is observed that there is water override in B_Upper. The B_Upper layer is being waterflooded very efficiently, while the B_Lower layer remains largely unflooded and forms the key target for enhanced oil recovery (EOR).

The proposed SIMGAP pilot plans to inject polymer into the B_Upper layer and CO₂ into the B_Lower layer with producers in the B_Lower layer. The pilot will utilize a line drive pattern at 250m spacing using 3000 ft horizontal wells. There will be two central horizontal injectors (one in B_Upper and the other in B_Lower) and two horizontal producers (one on either side of the central injectors).

Pilot uncertainty analysis cases have been run by varying different parameters that could impact the pilot performance. The parameters that have been varied are polymer viscosity, polymer adsorption, residual resistance factor, thermal stability of polymer, residual oil to miscible flooding (Sorm), residual oil to water flooding (Sorw), Krw end point, high perm streaks, fracture possibility and extension to B_Upper or B_Lower layers, three phase oil relative permeability models, maximum trapped gas saturation, dense zone permeability and pore volume uncertainty. In addition, a grid sensitivity study was undertaken to test the sensitivity of the process to varying levels of dispersion. The results suggest that the key uncertainties which have impact on recovery are polymer viscosity, polymer adsorption, residual oil saturation to water and CO2, presence of high perm streaks and maximum trapped gas saturation values. Vertical observation wells located between the injector and producer wells (equivalent to 0.3 to 0.4 PV of CO₂ injection in B_Lower), will be used to confirm whether the SIMGAP process has been successful in containing CO₂ in the B_Lower layer and thereby suppressing crossflow.