Case Study of Condensate Dropout Effect in Unconventional Gas/Condensate Reservoirs with Hydraulically Fractured Wells

Condensate banking is a major issue in the production operations of gas condensate reservoirs. Increase in liquid saturation in the near-wellbore zone due to pressure decline below dew point, decreases well deliverability and the produced condensate-gas ratio (CGR). This paper investigates the effects of condensate banking on the deliverability of hydraulically fractured wells producing from ultralow permeability (0.001 to 0.1 mD) gas condensate reservoirs. Cases where condensate dropout occurs over a large volume of the reservoir, not only near the fracture face, were examined by a detailed numerical reservoir simulation. A commercial compositional simulator with local grid refinement (LGR) around the fracture was used to quantify condensate dropout as a result of reservoir pressure decline and its impact on well productivity index (PI). The effects of gas production rate and reservoir permeability were investigated. Numerical simulation results showed a significant change in fluid compositions and relative permeability to gas over a large reservoir volume due to pressure decline during reservoir depletion. Results further illustrated the complications in understanding the PI evolution of hydraulically fractured wells in "unconventional" gas condensate reservoirs and illustrate how to correctly evaluate fracture performance in such a situation. The findings of our study and novel approach help to more accurately predict post-fracture performance. They provide a better understanding of the hydrocarbon phase change not only near the wellbore and fracture, but also deep in the reservoir, which is critical in unconventional gas condensate reservoirs. The optimization of both fracture spacing in horizontal wells and well spacing for vertical well developments can be achieved by improving the ability of production engineers to generate more realistic predictions of gas and condensate production over time.

Achieving stomal continence with an ileal pouch and a percutaneous implant

In this study, a soft-tissue-anchored, percutaneous port used as a mechanical continence-preserving valve in reservoir ileo- and urostomies was functionally and morphologically evaluated in eight dogs. During follow-up, the skin failed to attach to the implant, but the intestine inside the stoma port appeared to be attached to the mesh. After reaching adequate reservoir volume, the urostomies were rendered continent by attaching a lid to the implant. The experiments were ended at different time intervals due to implant-related adverse events. In only one case did the histological evaluation reveal integration at both the implant-intestine and implant-skin interfaces, with a low degree of inflammation and the absence of bacterial colonisation. In the remaining cases, integration was not obtained and instead mucosal downgrowth and biofilm formation were observed. The skin-implant junction was characterised by the absence of direct contact between the epidermis and the implant. Varying degrees of epidermal downgrowth, granulation tissue formation, inflammatory cell infiltration and bacterial growth and biofilm formation were prominent findings. In contrast, the subcutaneously located anchor part of the titanium port was well integrated and encapsulated by fibrous tissue. These results demonstrate the opportunity to achieve integration between a soft-tissue-anchored titanium port, skin and intestine. However, predictable long-term function could not be achieved in these animal models due to implant- and non-implant-related adverse events. Unless barriers at both the implant-skin and implant-intestine junctions are created, epidermal and mucosal downward migration and biofilm formation will jeopardise implant performance.

A Systematic Study of Ammonia Recovery from Anaerobic Digestate Using Membrane-Based Separation

Ammonia recovery from synthetic and real anaerobic digestates was accomplished using hydrophobic flat sheet membranes operated with H2SO4 solutions to convert ammonia into ammonium sulphate. The influence of the membrane material, flow rate (0.007, 0.015, 0.030 and 0.045 m3 h−1) and pH (7.6, 8.9, 10 and 11) of the digestate on ammonia recovery was investigated. The process was carried out with a flat sheet configuration at a temperature of 35 °C and with a 1 M, or 0.005 M, H2SO4 solution on the other side of the membrane. Polytetrafluoroethylene membranes with a nominal pore radius of 0.22 µm provided ammonia recoveries from synthetic and real digestates of 84.6% ± 1.0% and 71.6% ± 0.3%, respectively, for a membrane area of 8.6 × 10−4 m2 and a reservoir volume of 0.5 L, in 3.5 h with a 1 M H2SO4 solution and a recirculation flow on the feed side of the membrane of 0.030 m3 h−1. NH3 recovery followed first order kinetics and was faster at higher pHs of the H2SO4 solution and recirculation flow rate on the membrane feed side. Fouling resulted in changes in membrane surface morphology and pore size, which were confirmed by Atomic Force Microscopy and Air Displacement Porometry.

CO2 Waterless Fracturing and Huff and Puff in Tight Oil Reservoir

CO2 fracturing technique is a kind of ideal waterless stimulation tech. It has the advantages of water free, low reservoir damage, and production increase by improving the reservoir pressure. At the same time, combined with reasonable shut-in control after fracturing, it can be realized integrated development technology of energy storage -fracturing and oil displacement with CO2 waterless stimulation. For low-grade and low-permeability tight reservoirs, through the integration technology of CO2 fracturing and CO2 flooding, fracture-type "artificial permeability" is formed in the formation, and micro-nano pore throat of underground matrix is formed as oil and gas production system, which realizes the development of artificial energy, reduces carbon emissions, effectively improves the productivity of low-permeability and tight reservoirs, thus further improves oil recovery. The technology mainly includes two aspects: vertical wells adopt CO2 fracturing + huff and puff displacement integration technology, horizontal wells adopt water-based fracturing + CO2 displacement technology, and utilize the high efficiency of CO2 penetration in reservoirs and crude oil viscosity reduction, which can greatly improve oil recovery, while achieving large-scale CO2 storage and reducing carbon emissions. It is both realistic and economic, and has great social benefits. The integrated development technology of energy storage -fracturing and oil displacement with CO2 waterless stimulation has been applied for 10 wells in oilfield, which has achieved good results in increasing reservoir volume, increasing formation energy, reducing oil viscosity and enhancing post-pressure recovery. As a result, the production of them has increased by over 100%. With low viscosity and high diffusion coefficient, supercritical CO2 is good for improving fracturing volume. Effective CO2 fracturing technology can improve stimulated reservoir volume, downhole monitoring results show that the cracks formed by CO2 fracturing is 3 times the size of those formed by water-based fracturing.

In-situ Combustion Simulation from Laboratory to Field Scale

In-situ combustion simulation from laboratory to field scale has always been challenging, due to difficulties in deciding the reaction model and Arrhenius kinetics parameters, together with erroneous results observed in simulations when using large-sized grid blocks. We present a workflow of successful simulation of heavy oil in-situ combustion process from laboratory to field scale. We choose the ongoing PetroChina Liaohe D block in-situ combustion project as a case of study. First, we conduct kinetic cell (ramped temperature oxidation) experiments, establish a suitable kinetic reaction model, and perform corresponding history match to obtain Arrhenius kinetics parameters. Second, combustion tube experiments are conducted and history matched to further determine other simulation parameters and to determine the fuel amount per unit reservoir volume. Third, we upscale the Arrhenius kinetics to the upscaled reaction model for field-scale simulations. The upscaled reaction model shows consistent results with different grid sizes. Finally, field-scale simulation forecast is conducted for the D block in-situ combustion process using computationally affordable grid sizes. In conclusion, this work demonstrates the practical workflow for predictive simulation of in-situ combustion from laboratory to field scale for a major project in China.

Analysis, Logic, Considerations, Mitigations, Risk Assessments and Procedure to Drill Horizontal Gas Well With Separation Factor Up to 0.6 between the Ellipses Avoiding Collision in Exploratory Field. Bio-UC Project at Abu Dhabi, United Arab Emirates

In a current oil & gas challenging drilling environment where the fields are becoming very congested, PAD drilling and field grid designs with close proximity wells operation is booming. Drilling challenging wells with high collision risks is common as a result of the requirement to maximize the Asset value of the oil fields. For this reason, the urge for ensuring accurate well placement is becoming critical and as a result high technology methods are required to be in place. Developing new areas where the poor and/or inaccurate drilled wells information (most of them are vertical) affect planning and placement of new wells due to the uncertainty in existing wells trajectories, causing collision issues among the new planning and the "trajectory" of the existing wells, leaving huge quantities of reservoir volume not possible to drain. For this study case, where the reservoir has some complexity due to faults and water, such limitation is critical. The analysis and fusion of new techniques and procedure to manage the risk for the collision were implemented. Directional tools with high level of accuracy measurements were deployed and stringent procedures are put in place. The Analysis, Logic, Considerations, Mitigations, Risk Assessments and a New Procedure implemented to avoid collision issues while drilling horizontal wells with Separation Factor (SF) less than 2 (standard worldwide is equal or above 2 and for this case, it was 0.6). This was developed by the Biogenic / Unconventional team, Drilling Department of Abu Dhabi National Oil Company (ADNOC) Onshore with the support of drilling service company and the approval of the ADNOC Head Quarter, to take advantage of around 0.9 km2 of hydrocarbon area for future drain. The well was drilled successfully and safely, no collision or magnetic interference issue in any trajectory survey were reported during drilling and passing close by the existing well.

Design of an Economical Polymer Flood Pilot Addressing Field Development Uncertainties in the Sabriyah Upper Burgan Reservoir of North Kuwait

The Sabriyah Upper Burgan is a major oil reservoir in North Kuwait with high oil saturation and is currently considered for mobility control via polymer flooding. Although there is high confidence in the selected technology, there are technological and geologic challenges that must be understood to transition towards phased commercial field development. Engineering and geologic screening suggested that chemical flood technologies were superior to either miscible gas or waterflood technologies. Of the chemical flood technologies, mobility control flooding was considered the best choice due to available water ion composition and total dissolved solids (TDS). Evaluation of operational and economic considerations were instrumental in recommending mobility control polymer flooding for pilot testing. Laboratory selected acceptable polymer for use with coreflood incremental oil recovery being up to 9% OOIP. Numerical simulation recommended two commercial size pilots, a 3-pattern and a 5-pattern of irregular five spots, with forecast incremental oil recovery factors of 5.6% OOIP over waterflood. Geologic uncertainty is the greatest challenge in the oil and gas industry, which is exacerbated with any EOR project. Screening of the Upper Burgan reservoirs indicates that UB4 channel sands are the best candidates for EOR technologies. Reservoir quality is excellent and there is sufficient reservoir volume in the northwest quadrant of the field to justify not only a pilot but also future expansion. There is a limited edge water drive of unknown strength that will need to be assessed. The channel facies sandstones have porosities of +25%, permeabilities in the Darcy range, and initial oil saturations of +90%. Pore volume (PV) of the two recommended pilot varies from 29 to 45 million barrels. A total of 0.7 PV of polymer is expected to be injected in 5.6 and 7.9 years for the 3-pattern pilot and the 5-pattern pilot, respectively, with a water drive flush to follow for an additional 5 to 7 years. Incremental cost per incremental barrel of oil of a mobility control polymer flood which includes OPEX and CAPEX costs is $20 (USD). This paper evaluates the (commercial size) pilot design and addresses field development uncertainties.