一旦油藏的一次压力耗尽且二次注水完成后，运营商通常会采用 EOR 方法将剩余的可采油桶抽至地面。在过去三十年中，EOR 工作（特别是利用 CO ₂注入的传统油藏三次采油方法）使美国的石油产量呈指数级增长。根据 Advanced Resources International 的数据，1986 年，通过CO ₂注入。到 2012 年，这一量增长到超过 275 Mbbl/d，增长了 1,000%。

2010 年代中期，随着石油突破 100 美元大关，CO ₂ EOR 具有很大的经济意义。据 CO ₂ EOR 咨询公司 Melzer Consulting 称，运营商以每桶价格 2% 的成本与 CO ₂供应商签订了长期合同。但到 2016 年，由于油价低迷，许多 EOR 工作被搁置。

“那些以 [每桶石油成本 2%] 的价格签订 CO ₂合同的公司陷入了相当困境，有时甚至不得不寻找新买家并退出合同，” ”梅尔泽咨询公司创始人史蒂夫·梅尔泽说道。“我们见过好几个这样的例子。那些没有繁重合同的公司仍然表现良好，他们的目的是度过这些风暴。这成为我们行业的重要组成部分。”

_{一些运营商正在发现 CO 2} EOR的价值，并且可能会继续这样做，特别是那些维护自己的基础设施和 CO ₂来源的运营商。

看到 EOR 的机会

经济低迷之后，一些运营商开始出售成熟油田，而不是实施 CO ₂ EOR 方法，以腾出现金在其他地方开展工作。他们经常向那些拥有技术独创性、财务手段或适当基础设施的公司出售产品，以通过 EOR 获利。

Hess 和西方石油公司 (Oxy) 6 月 19 日宣布，Oxy 以 6 亿美元收购了 Hess 在二叠纪盆地的 EOR 资产，此举为 Oxy 提供了 8,200 桶油当量/日的产量。该交易包括 Hess 在 Seminole-San Andres 装置、德克萨斯州塞米诺尔天然气加工厂、West Bravo Dome CO ₂油田的工作权益以及在新墨西哥州 Bravo Dome 装置的 9.9% 的非经营权益。

Chaparral Energy 在 3 月份摆脱破产保护后不久，于 4 月份宣布将出售其 EOR 资产，其中包括北伯班克装置和俄克拉荷马州 Panhandle 的8 次 CO _2洪水。该公司宣布将集中资源专门开发 STACK 游戏资产。

Fleur de Lis Energy (FDL) 于 2016 年 8 月以 4.225 亿美元从 Devon Energy 购买了二叠纪盆地的 EOR 资产，并于 2016 年 9 月以 7500 万美元从 Summit Energy 购买了 EOR 资产。2015年，FDL以7.03亿美元收购了阿纳达科石油公司在怀俄明州的EOR资产。FDL在交易中收购的资产包括Salt Creek Field、Monell Field、Linch Field和Howell Pipeline，净产量约为14 Mboe/d，CO ₂管道容量为7.6 MMcm/d (270 MMcf/d)。

“在所有这些西德克萨斯油田，注水后仍然剩余大量石油，”莱斯大学化学和生物分子工程教授乔治平崎说。“但公司已经放弃了[这些领域]。一些公司引入CO ₂并将其注入，现在得到了很大的反响。你会看到更多这样的事情发生。”

二叠纪盆地占地 50,000 英亩的 Scurry Area Canyon Reef Operators (SACROC) 油田的故事就是这种动态的代表。SACROC 于 1948 年被发现，估计原始石油储量为 2.8 Bbbl，成为美国第一个进行 CO ₂ EOR 注入的油田，该注入于 1972 年开始。自那时起，已注入超过 1.75 亿吨 CO ₂水库。随着时间的推移，甚至在注入 CO _{2 的}情况下，该油田的产量在 2000 年也减少至约 8 Mbbl/d。就在那时，Kinder Morgan 购买了该业务。

“我们发现洪水模式配置存在一些低效问题，” Kinder Morgan CO _{2业务部门总裁 Jesse Arenivas 说道。}——但我们看到了很多好处。我们可以看到，通过改变模式配置，我们的产量在几年内增加了两倍，并且十多年来我们一直能够保持每天 30,000 桶的产量。”

金德摩根利用其在科罗拉多州科尔特斯采购的CO _{2优势，通过在油田南端开始注入并一直延伸至北部平台，优化了洪水模式。}该计划在 2014 年实现了 38 Mbbl/d 的峰值产量。据 Kinder Morgan 称，此后 SACROC 的产量逐渐降至 30 Mbbl/d 左右。金德摩根 (Kinder Morgan) 的一个相对较新的项目是其 Chiquita 区域，该区域于 2010 年在 SACROC 启动，初始投资 1,500 万美元。该项目于 2014 年和 2016 年进行了两次扩建。该公司表示，最初的努力取得了良好的成果，此后在目标过渡区投资了超过 1 亿美元，也取得了类似的成果。

二叠纪盆地最大的 CO ₂ EOR 运营商是 Oxy，运营着 19,300 多口井，目前拥有 100 口活跃的 CO ₂和注水井。该公司向二叠纪储层注入超过 56.6 MMcm/d (2 Bcf/d) 的 CO _{2 。}Oxy 2017 年第一季度二叠纪 EOR 产量约为 145 Mboe/d。

_{“我们目前正在从格雷堡一直到泥盆纪地层开采碳氢化合物，并在我们的一些 CO 2}驱油中实现了 60% 以上的采收率，”Oxy's Oil & Gas Domestic 总裁乔迪·埃利奥特 (Jody Elliott) 说。“2015 年底，我们在新墨西哥州的南霍布斯工厂开始了 CO _{2洪水的第一阶段。}CO ₂驱油正在显示出反应，自上线以来产量增加了两倍多。”

2月，Denbury宣布，在2017年3亿美元的资本预算中，1.75亿美元将分配给三级油田支出，1000万美元将用于CO ₂来源和管道。通过在其墨西哥湾沿岸和落基山资产中利用 CO _{2洪水，Denbury 预计产量将在 58 Mboe/d 至 62 Mboe/d 之间。}

Denbury 首席执行官 Phil Rykhoek 表示：“在当前价格环境下，我们的资本支出仍然主要集中在扩大现有的 CO ₂洪水和其他填充机会，并且‘我们计划的 2017 年资本项目在 50 美元油价下具有强劲的经济性。’”一个释放。Kinder Morgan 和 Denbury 的独特之处在于，他们拥有自己的 CO ₂源田和管道等基础设施，这大大降低了三次回收的成本。

“我们的产品组合在价格较低的情况下非常强劲，主要是因为我们正在利用现有的基础设施，”阿雷尼瓦斯说。“当您希望在没有现有基础设施的情况下开发新的 CO ₂项目时，您必须提供比我们目前的价格更高的价格才能使其发挥作用。但 Yates 和 SACROC 的基础设施非常丰富，因此我们能够继续利用这些现有设施钻井。”

Tall Cotton 项目位于塞米诺尔西北部二叠纪盆地，是一个未开发的残余油区CO ₂项目。据 Kinder Morgan 称，高棉田是第一个没有主产层、专为 CO ₂技术开发的油田。该项目于 2014 年开始，为 Kinder Morgan 的产量增加了约 2 Mbbl/d。

EOR 的经济学

此前的大宗商品低迷（例如该行业目前正在经历的低迷）并不一定会成为 CO ₂实施的障碍。例如，根据北达科他州能源与环境研究中心(EERC)的数据，2000年，加拿大萨斯喀彻温省的Weyburn油田实施了CO _{2注入，当时西德克萨斯中质原油的交易价格为28美元/桶。}据经营该油田的加拿大石油公司 Cenovus Energy 称，大约七年后，Weyburn 的日产量超过 30 Mbbl，这是该油田自 20 世纪 70 年代初以来从未见过的产量。

_{影响 CO 2} EOR广泛利用的另一个动力是私募股权公司进军二叠纪页岩热潮的趋势。梅尔泽表示，与长期的 EOR 相比，二叠纪盆地页岩现象的产油速度更快，为公共和私人投资者提供了更快的财务回报。

“私募股权市场正在寻求从页岩水平井中获得快速回报——这是他们想要投资的领域，”他说。“他们想进又出。他们不愿意开展利用CO _{2 的长期项目。}我们看到的是，更好的市场不太适合 CO ₂世界。股票等公开市场也有几乎相同的态度。上市公司获得快速回报的机会是巨大的。很少有人投资 CO ₂ EOR。氧气是唯一的例外。”

进入壁垒

运营商在考虑实施 EOR 方法时面临的最重大挑战是缺乏足够的 CO ₂。

_{“CO 2}短缺已经造成了一个真正的问题，”梅尔泽说。“我们看到的是，CO ₂是可用的，但它是供应商，他们不能出去销售。它是根据合同签订的。”

_{CO 2}供应短缺问题在巴肯尤其麻烦，根据 EERC 的数据，研究人员和工程师非常清楚，EOR 可以回收高达 45% 的原始石油，即 670 MMbbl。

“当巴肯号于 2008 年和 2009 年开始投入使用时，很明显[运营商]仅恢复了 3% 至 6%，因此自然而然地出现了一个问题：“巴肯号的 CO 2 是多少？_” EERC 首席地质学家 Jim Sorensen 说道。

他补充说，北达科他州非常需要 CO ₂注入方法，但可能需要数年时间才能获得足够的产品。

“至少对于威利斯顿盆地，我认为我们的实验室工作表明 CO ₂效果很好，但目前确实没有太多 CO _{2可用，”他说。}“至少需要五到十年才能有更多的产品出现。”

请通过bwalzel@hartenergy.com联系作者。

Once a reservoir’s primary pressure has depleted and its secondary waterflood has run its course, operators often turn to EOR methods to draw the remaining recoverable barrels of oil to the surface. During the past three decades EOR efforts—particularly conventional reservoir tertiary methods that utilize CO₂ injection—have exponentially increased the amount of oil produced in the U.S. According to Advanced Resources International, in 1986 about 25 Mbbl/d of oil was produced via CO₂ injection. By 2012 that amount grew to more than 275 Mbbl/d, an increase of 1,000%.

In the mid-2010s, with oil eclipsing the $100 mark, CO₂ EOR made plenty of economic sense. According to Melzer Consulting, a CO₂ EOR consulting firm, operators were locking in long-term contracts with CO₂ providers at costs of 2% of the price of a barrel. But by 2016 many EOR efforts were put on hold because of low oil prices.

“Those companies that had contracted their CO₂ for [2% of the cost of a barrel of oil] got in a pretty distressed position, sometimes to the point where they had to find a new buyer and get out of that contract,” said Steve Melzer, founder of Melzer Consulting. “We saw several cases of that. Companies that didn’t have onerous contracts are still doing fine—their intent was to weather these storms. That became a big part of our industry.”

Some operators are finding value in CO₂ EOR and likely will continue to do so, particularly those that maintain their own infrastructure and sources of CO₂.

Seeing opportunities in EOR

Following the downturn, some operators began selling off mature fields rather than implementing CO₂ EOR methods to free up cash to do work elsewhere. They often sell to those companies with the technical ingenuity, the financial means or the right infrastructure in place to turn a profit through EOR.

Hess and Occidental Petroleum (Oxy) announced June 19 that Oxy purchased Hess’ EOR assets in the Permian Basin for $600 million, a move that provides Oxy an influx in production of 8,200 boe/d. The transaction included Hess’s working interest in the Seminole-San Andres unit, the Seminole Gas Processing Plant in Texas, the West Bravo Dome CO₂ field and a 9.9% nonoperating interest in the Bravo Dome unit in New Mexico.

Shortly after it emerged from bankruptcy in March, Chaparral Energy announced in April that it was selling off its EOR assets, which comprise eight CO₂ floods in the North Burbank unit and the Panhandle in Oklahoma. The company announced it would instead focus its resources exclusively in developing its STACK play assets.

Fleur de Lis Energy (FDL) purchased EOR assets in the Permian Basin from Devon Energy in August 2016 for $422.5 million and from Summit Energy in September 2016 for $75 million. In 2015 FDL purchased Anadarko Petroleum’s EOR assets in Wyoming for $703 million. The assets FDL acquired in the deal included the Salt Creek Field, Monell Field, Linch Field and Howell Pipeline, with about 14 Mboe/d of net production and CO₂ pipeline capacity of 7.6 MMcm/d (270 MMcf/d).

“In all of these West Texas fields there is still a lot of oil remaining after waterflooding,” said George Hirasaki, professor of chemical and biomolecular engineering at Rice University. “But companies have abandoned [the fields]. Some companies come in with CO₂ , inject it and are now getting a big response. You’ll see a lot more of that happening.”

The story of the 50,000-acre Scurry Area Canyon Reef Operators (SACROC) Field in the Permian Basin is representative of such a dynamic. Discovered in 1948 with an estimated original oil in place of 2.8 Bbbl, SACROC became the first field in the U.S. to undergo CO₂ EOR injection, which began in 1972. Since that time more than 175 million metric tons of CO₂ have been injected into the reservoir. Over time and even under CO₂ injection the field’s output depleted to about 8 Mbbl/d in 2000. That’s when Kinder Morgan purchased the operation.

“We saw some inefficiencies in the flood pattern configuration,” said Jesse Arenivas, CO₂ business unit president for Kinder Morgan. “But we saw a lot of upside. We could see that by changing the pattern configuration, we tripled the production in a couple of years, and we have been able to maintain a rate of 30,000 barrels per day for over a decade.”

Kinder Morgan, with the benefit of leveraging its own CO₂ sourced in Cortez, Colo., optimized the flood pattern by initializing injections in the southern end of the field and working its way up to the northern platform. That plan resulted in peak production of 38 Mbbl/d in 2014. Since then SACROC production has been tapering down to about 30 Mbbl/d, according to Kinder Morgan. A relatively new venture for Kinder Morgan is its Chiquita area, which was activated in the SACROC in 2010 with an initial investment of $15 million. The project underwent an expansion in 2014 and again in 2016. The company said it achieved favorable results from the initial effort and has since invested more than $100 million in the targeted transition zone with similar results.

The Permian Basin’s largest CO₂ EOR operator is Oxy, which operates more than 19,300 wells, and currently has 100 active CO₂ and waterfloods. The company injects more than 56.6 MMcm/d (2 Bcf/d) of CO₂ into reservoirs in the Permian. Oxy’s first-quarter 2017 Permian EOR production was about 145 Mboe/d.

“We are currently recovering hydrocarbons from the Grayburg down to the Devonian formations and realizing recovery factors above 60% in some of our CO₂ floods,” said Jody Elliott, president at Oxy's Oil & Gas Domestic. “At the end of 2015 we began Phase 1 of a CO₂ flood at our South Hobbs Unit in New Mexico. The CO₂ flooding is showing response, with production more than tripling since going online.”

In February Denbury announced that of its $300 million 2017 capital budget $175 million would be allocated for tertiary oilfield expenditures, and $10 million would be spent on CO₂ sources and pipelines. By utilizing CO₂ floods at its Gulf Coast and Rocky Mountain assets, Denbury anticipates producing between 58 Mboe/d and 62 Mboe/d.

“Our capital spending in the current price environment continues to be primarily focused on expanding our existing CO₂ floods and other infill opportunities, and … our planned 2017 capital projects have strong economics at $50 oil,” said Denbury CEO Phil Rykhoek in a release. Kinder Morgan and Denbury are unique in that they own their own CO₂ source fields and infrastructure like pipelines, which cuts down substantially on their costs for tertiary recovery.

“Our portfolio is very robust at lower prices, primarily because we are utilizing existing infrastructure,” Arenivas said. “When you’re looking to develop a new CO₂ project without existing infrastructure, you have to have higher prices than what we are currently experiencing to make them work. But Yates and SACROC are very infrastructure-rich, so we are able to continue to drill wells utilizing those existing facilities.”

Tall Cotton, located in the Permian Basin northwest of Seminole, is a greenfield residual oil zone CO₂ project. Tall Cotton is the first field without a main pay zone to be specifically developed for CO₂ technology, according to Kinder Morgan. The project began in 2014 and has added about 2 Mbbl/d to Kinder Morgan’s production.

Economics of EOR

Previous commodity downturns such as the one the industry currently is experiencing have not necessarily proven to be a roadblock for CO₂ implementation. For example, according to the Energy and Environmental Research Center (EERC) in North Dakota, CO₂ injection was implemented at the Weyburn oil field in Saskatchewan, Canada, in 2000 when West Texas Intermediate was trading for $28/bbl. About seven years later Weyburn was producing more than 30 Mbbl/d, an amount not seen in that field since the early 1970s, according to Cenovus Energy, a Canadian-based oil company operating the field.

Another dynamic impacting the widespread utilization of CO₂ EOR is the trend of private-equity firms making a foray into the Permian shale boom. The Permian Basin shale phenomenon, which is producing oil more rapidly compared to the longer play of EOR, offers a quicker financial return for investors, both public and private, Melzer said.

“The private-equity market is looking for fast returns from horizontal wells in shale—that’s where they want to invest,” he said. “They want to get in and get out. They’re not comfortable doing a long-term project where CO₂ would be utilized. What we’re seeing is that the better market is not very amenable to the CO₂ world. The public market with stocks and the like has almost the same attitude. The opportunity for quick returns for public companies is overwhelming. Very few are investing in CO₂ EOR. Oxy is the only exception.”

Barriers to entry

The most significant challenge operators face when considering implementing EOR methods is a lack of access to enough CO₂.

“A shortage of CO₂ has caused a real issue,” Melzer said. “What we’re seeing is that CO₂ is available, but it’s the suppliers— they can’t go out and sell it. It’s under contract.”

The issue of CO₂ supply shortages is particularly troublesome in the Bakken, where researchers and engineers pretty well know EOR could recover up to 45% of original oil in place—as much as 670 MMbbl of oil, according to the EERC.

“When the Bakken started coming on in 2008, 2009, and as it became clear [operators] were only recovering 3% to 6%, it became a natural question—‘Is CO₂ for the Bakken?’” said Jim Sorensen, EERC principal geologist.

He added that there is a substantial need for CO₂ injection methods in North Dakota, but it could be years before enough product becomes readily available.

“At least for the Williston Basin, I think our lab work demonstrates CO₂ works well, but there really isn’t much CO₂ available right now,” he said. “And it will be at least five to 10 years before more becomes available.”

Contact the author at bwalzel@hartenergy.com.