Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. A seismic measurement involving a seismic source on the Earth surface and a seismic sensor suspended by wireline in a well. The objective is to measure the travel time required for a seismic wavelet to travel from the Earth's surface to the downhole receiver. Check-shot data allow interpreters to convert seismic image times to stratigraphic depth (or vice versa).
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. In a seismic context, a check shot survery determines formation seismic wave velocities over specific intervals. Measurement is made of travel time from surface to downhole geophones.
Investors and operators like to draw attention to the lengthy history of oil production from the Permian. Benefits include well-known reservoirs and lower cost brownfield options for services and infrastructure. Today's boom mirrors prior periods of intense Permian activity, but using prior comparisons of tight oil reservoir behavior can result in dangerous conclusions.
The Permian houses thousands of vertical wells that have been online for decades. The actual terminal decline rates of those wells can be modeled with empirical data, and our analysis shows that they sit between 5% and 10% annually. However, pure field data for horizontal tight oil wells does not go back as far, so terminal decline values from vertical wells or general ‘shale’ declines are often applied to Wolfcamp type curves as a proxy. This is a risky practice.
Building evidence suggests that the most active Wolfcamp sub-plays may eventually still have annual decline rates greater than 10% five or more years into their lifespan. Not recognizing this and modeling with the lower proxy value from older, analogue tight oil plays could result in overstating production potential and overvaluing projects. Wolfcamp players without exposure to other basins may need to resort to M&A to fill production gaps. We are already seeing signs of this in 2018 deals with Concho and Diamondback using M&A to acquire larger undrilled acreage footprints.
In many cases, Permian tight oil wells realize more than 40% of the estimated ultimate recovery (EUR) within only 36 months of being online. Nearly 50% net present value (NPV) is realized by year five. Rightfully so, we have observed the analytical focus being placed on each well's first few years. This emphasis has also been driven by the limited number of tight oil wells with more than five years’ worth of production history. Less than 20% in the Permian tight oil wells have been producing more than 60 months.
As the Wolfcamp play matures, the later-life performance of wells starts to matter more. Even with record rig counts, the number of new wells drilled each year becomes a smaller proportion of the total wells contributing to supply.
Pineda, Wilson (BP) | Wadsworth, Jennifer (BP) | Halverson, Dann (BP) | Mathers, Genevive (BP) | Cedillo, Gerardo (BP) | Maeso, Carlos (Schlumberger) | Maggs, David (Schlumberger) | Watcharophat, Hathairat (Schlumberger) | Xu, Weixin (Wayne) (Schlumberger)
Deepwater depositional environments in the Gulf of Mexico can be very complex. Accurate determination of depositional facies is important in these capital-intensive fields. The most common reservoir facies are laterally extensive sheet sandstones with thin mudrock layers, channel complexes (isolated or amalgamated) and channel-levee complexes (often with poor reservoir communication). Reservoirs are often complicated by steep dips close to salt domes and the presence of potential fluid conduits due to faults or fractures. Borehole images aid in determining the character of the sediments, as well as improve net sand calculations, and illuminate the geology in the near wellbore region both in structure and depositional environment, and to provide valuable geomechanics information for the determination of the stress vector.
A well was recently drilled through one of these deep water sediment sequences in the Gulf of Mexico with an oil-based mud (OBM) system. An extensive acquisition program included a series of logging while drilling (LWD) and wireline images. In addition to the current LWD lower resolution borehole imaging tools, a new LWD dual physics OBM imager was deployed for the first time in this field. Five different types of physics were acquired, including lower-resolution images from nuclear measurements (gamma ray, density and photoelectric) and the high-resolution images from dualphysics OBM imager (DPOI) which is based on resistivity and ultrasonic measurements. Wireline high-resolution OBM resistivity images were also acquired. This paper shows a comparison of images collected with the new DPOI versus traditional LWD images and high-resolution wireline resistivity images.
Comparisons of the types of features observed from the various imaging tools were made, showing how the differences in physics, resolution and time of logging affects the images, as well as the impact these factors can have on subsequent interpretations. Four main categories of features are included in comparisons between the tools: sand-rich sections, consistently dipping mudrocks, chaotic zones and fractures/faults. The different images allow fuller interpretation of the gross sequence. In general, the higher the resolution, the more detailed and confident the interpretation is, particularly where the hole conditions are good. In degraded borehole sections, the LWD acquisition was beneficial for obtaining images as early as possible, when damage was at a minimum. The impact of the differences in the physics depends on the properties and contrasts being imaged. This is observed with fractures - both conductive and resistive examples can be seen on both LWD and wireline images. The ultrasonic images are complementary with both low and high amplitude fractures seen, providing more confidence in the fracture interpretation.
The aim of this paper is to compare the performance of three horizontal infill wells in a mature field, of which one is completed with autonomous inflow control devices (AICDs). The analytic results are based on the comparison of oil production rates; water cut development and water-oil ratio plots of the wells. All the wells in this study are producing from the same homogeneous sandstone reservoir.
Two of the horizontal infill wells are targeting attic oil in an area with low risk of gas production of which one of these wells is completed with slotted liners and the other with AICDs. Both are artificially lifted with high rate electrical submersible pumps (ESPs). The third horizontal well was placed in an area with higher gas saturation, where a completion with casing, cementation and perforation was used. The performance of the horizontal wells is compared against each other.
The use of active geo-steering successfully supported the well placement into the "sweet spot" of the reservoir due to real-time well path adjustments.
It was found that the AICDs choke back a high amount of fluid and keep the water cut at a stable plateau level. This observation underlines the key benefit of using AICDs as when comparing to the other producing wells without AICDs, the water cut is steadily increasing.
Therefore the use of AICDs is a real option for horizontal well completion.
This paper will be useful to those who are in a phase of early well planning, e.g. in a field (re-)development project and have to select the best well concept (e.g. slotted liner vs. AICDs). AICDs have proven their value even in a super-mature oil field by improving production. Further advantages and challenges during operation are discussed in this paper.
Abdulhadi, Muhammad (Dialog Group) | Tran, Toan Van (Dialog Group) | Chin, Hon Voon (Dialog Group) | Jacobs, Steve (Halliburton) | Suggust, Alister Albert (PETRONAS) | Usop, Mohammad Zulfiqar (PETRONAS) | Zamzuri, Dzulfahmi (PETRONAS) | Dolah, Khairul Arifin (PETRONAS) | Abdussalam, Khomeini (PETRONAS) | Munandai, Hasim (PETRONAS) | Yusop, Zainuddin (PETRONAS)
The first successful natural dump-flood in the Malaysian offshore environment provided numerous lessons learned to the operator. The minimal investment necessary for implementing the dump-flood coupled with the lack of recompletion opportunities in the subject wells suggested that direct execution without spending on expensive data gathering activity and extensive reservoir study makes more sense from a business point of view. A similar oil gain compared to a water injection project can be achieved at a significantly lower cost of USD 0.01 to 0.15 million in an offshore environment through dump-flooding.
The existing oil producers in the depleted reservoirs in Field B were originally completed and successfully drained oil from in a high-pressured watered-out reservoir below, making it an ideal dump-flood water source. The dump-flood was initiated by commingling the target and water source reservoir through zone change, allowing water to naturally cross-flow into the pressure depleted target reservoir. Once a memory production logging tool (MPLT) confirmed the cross-flow, the offtake well was monitored to determine the impact of the dump-flood and produce once the pressure was increased. Minimal investment was necessary because the operations were executed using slickline. The reservoir model will be calibrated once the positive impact of dump-flood is realized in the offtake well.
The first natural dump-flood in Reservoir X-2 has successfully produced 0.29 MMstb as of August 2018 with 600 BOPD incremental oil gain. The incremental recovery factor (RF) from the first dump-flood is predicted to be from 5 to 8%. Based on this success, it was decided to replicate the dump-flood project in other depleted reservoirs with Reservoir X-2 as an analog. Four reservoirs were subsequently identified, each with an estimated operational cost of approximately USD 0.01 million and potential incremental reserves of 0.10 to 0.20 MMstb per reservoir. The minimal investment necessary, the idle status of the wells and reservoirs, and the potential incremental reserves suggested that it is more appealing to proceed with implementing the dump-flood without undergoing an extensive and costly reservoir study. With reservoir connectivity being important to the success of dump-flooding, a more cost-effective approach would be to confirm the connectivity by monitoring the offtake well after the dump-flood is initiated. This approach provides more value because the cost of interference or pulse testing is significantly more expensive than the cost of the dump-flood itself while reservoir connectivity was already indicated as likely by geological data (map and seismic). Through a value driven approach, these dump-flood opportunities become more economically viable, allowing the operator to prolong the life of the assets and maximize the field profit.
This paper discusses using a value driven and business approach to implement the dump-flood in a mature field. Valuable insight into the business and technical considerations of implementing dump-floods are described, which are relevant to the industry, especially in today's low margin business climate.
Barmer Hill Turbidites (BHT) are low permeability reservoirs in the Vijaya & Vandana field with an approximate in place reserve of a billion barrels. The field was discovered in 2004 with the discovery wells V-1 and V-2 respectively. Post drilling and completion these wells were tested without any stimulation technique, resulting in ~ 25 – 50 BOPD flow owing to tight nature of these formations. Subsequently the zones were hydraulically fractured and tested resulting in ~ 10 – 12 folds increase in the production rate of the oil. Also, the testing of multiple stacked reservoirs in these two wells further confirmed BHT-10 to be the most prolific zone in terms of commercial flow rates achievable. Apart from being tight formations, the low net to gross on reservoirs (<20%) further added to the challenges of devising a strategy to make these reservoirs flow at sustained commercial oil rates. Hence, when the field was taken for the next stage of a hydrocarbon field lifecycle i.e. the appraisal campaign, two very clear objectives were identified for achieving a successful appraisal campaign viz. hydraulically frac and test two of the existing wells in the field while aiming to connect the maximum available KH and ensure effective data acquisition through injection tests and temperature logs with an aim to calibrate the existing stress logs and eventually build a robust frac model.
The dynamic geo-mechanical parameters i.e. Young’s Modulus and Poisson’s Ration were calculated from the open hole sonic logs and were converted to static data using the lab measured value from the core tests. Stress logs generated from these static data points were used for the initial frac designing in the wells. During the execution phase of the frac campaign, at every opportunity available, injection tests were carried out and fall off data were acquired to estimate the closure pressures actually observed in these zones. Post acquiring the measured stress data, the earlier calculated stress logs were calibrated using these measured closure points (frac gradients) by incorporating the stress components due to strain factors (ɛmin & ɛmax) in both max and min direction of the principle stresses.
Post every data injection, temperature logs were also acquired. This gave a better control on frac height (hydraulic height) based on the cool downs observed on the temperature logs. This proved to be a very important data set in comparing the height predicted by the calibrated stress logs versus the height estimated from the temperature log cool downs. This step helped in gaining confidence on the model predictability. This also helped in real time frac design optimization and placement of perforation intervals for the main frac designs. Further, the entire model calibration exercise also helped in arriving at a porosity based leak off equation.
The paper endeavors to discuss in detail the entire workflow used during this appraisal campaign to arrive at a calibrated and a robust frac model whilst showcasing the journey taken from 50 BOPD to 500 BOPD in these tight oil sands to achieve ~ 10 fold production increase. Authors, further, emphasize on the importance of carrying out such data acquisitions during the appraisal phase of a field to gain better control on the models. This paper will also elaborate on the strategy deployed for these data acquisition to optimize the fracs in real time and to integrate different data sets for calibrating the geo-mechanical and frac simulation models.
The paper presents a case of applying classical reservoir engineering technique of material balance to one of the major carbonate reservoir in the western offshore basin in India that eventually led to establishment of more hydrocarbon volumes.
During Material Balance calculation, multiple runs were performed to match the pressure performance with a balance between the aquifer strength and hydrocarbon volume that was in agreement with geological understanding and performance of the field. The analysis indicated extra energy support that may be in the form of aquifer or higher in-place volumes. Following the in-house developed SIMEX (Simultaneous Exploration) approach a vertical well was identified for testing below assumed lowest known oil (LKO) limit.
The material balance study formed the basis for revisiting the geological understanding. The establishment of oil through the testing of well necessitated the revision of geological maps and re-estimation of hydrocarbon in-place volumes. Accordingly property maps have been prepared and volumes are revised. The revised volumes are about 14% more than the previous estimation. Similar approach was successfully applied to another reservoir in the Mumbai High field. Presence of more established oil will help in planning future strategies for field development.
Especially in fields where enough pressure production history is available, it is important to reassess the field's potential from time to time through simple and classical techniques available. Fields with multiple reservoirs have added advantage of developing the established hydrocarbons through zone transfer and in turn saving significant cost of drilling new well. This being a proven and classical technique, can be applied to other analogous reservoirs.